THE ECONOMICS OF WIND POWER

esco.ecosys.narod.ru

THE ECONOMICS OF WIND POWER

WIND ENERGY - THE FACTS

PART III

THE ECONOMICS

OF WIND POWER


Acknowledgements

Part III was compiled by Poul Erik Morthorst of

Risǿ DTU National Laboratory, Technical University of

Denmark; Hans Auer of the Energy Economics Group,

University of Vienna; Andrew Garrad of Garrad Hassan

and Partners; Isabel Blanco of UAH, Spain.

We would like to thank all the peer reviewers for

their valuable advice and for the tremendous effort

that they put into the revision of Part III.

Part III was carefully reviewed by the following

experts:

Rune Moesgaard

Hugo Chandler

Paulis Barons

Mr. G. Bakema

Danish Wind Industry Association

IEA

Latvian Wind Energy Association

Essent Netherlands


PART III

INTRODUCTION

Wind power is developing rapidly at both European

and global levels. Over the past 15 years, the global

installed capacity of wind power increased from around

2.5 GW in 1992 to just over 94 GW at the end of 2007,

an average annual growth of more than 25 per cent.

Owing to ongoing improvements in turbine efficiency and

higher fuel prices, wind power is becoming economically

competitive with conventional power production,

and at sites with high wind speeds on land, wind power

is considered to be fully commercial.

Part III of this volume focuses on the economics of

wind power. The investment and cost structures of

land-based and offshore turbines are discussed. The

cost of electricity produced is also addressed, which

takes into account the lifetime of turbines and O&M

costs, and the past and future development of the

costs of wind-generated power is analysed. In subsequent

chapters, the importance of finance, support

schemes and employment issues are discussed. Finally,

the cost of wind-generated electricity is compared to

the cost of conventional fossil fuel-fired power plants.

Wind power is used in a number of different applications,

including grid-connected and stand-alone

electricity production and water pumping. Part III

analyses the economics of wind energy, primarily in

relation to grid-connected turbines, which account

for the vast bulk of the market value of installed

turbines.


III.1

COST OF ON-LAND WIND POWER

Cost and Investment Structures

The main parameters governing wind power economics

include:

• investment costs, such as auxiliary costs for foundation

and grid connection;

• operation and maintenance costs;

• electricity production/average wind speed;

• turbine lifetime; and

• discount rate.

The most important parameters are turbine electricity

production and investment costs. As electricity

production depends to a large extent on wind conditions,

choosing the right turbine site is critical to

achieving economic viability.

INVESTMENT COSTS

The capital costs of wind energy projects are dominated

by the cost of the wind turbine itself (ex-works). 1

Table III.1.1 shows the typical cost structure for a 2 MW

turbine erected in Europe. An average turbine installed

Table III.1.1: Cost structure of a typical 2 MW wind turbine

installed in Europe (2006-€)

Investment (€1000/MW) Share (%)

Turbine (ex-works) 928 75.6

Foundations 80 6.5

Electric installation 18 1.5

Grid connection 109 8.9

Control systems 4 0.3

Consultancy 15 1.2

Land 48 3.9

Financial costs 15 1.2

Road 11 0.9

Total 1227 100

Note: Calculations by the author based on selected data for European wind turbine

installations.

Source: Risø DTU

in Europe has a total investment cost of around €1.23

million/MW. The turbine’s share of the total cost is, on

average, around 76 per cent, while grid connection

accounts for around 9 per cent and foundations for

around 7 per cent. The cost of acquiring a turbine

site (on land) varies significantly between projects, so

the figures in Table III.1.1 are only to be taken as

examples. Other cost components, such as control

systems and land, account for only a minor share of

total costs.

The total cost per kW of installed wind power capacity

differs significantly between countries, as shown

in Figure III.1.1. The cost per kW typically varies from

around €1000/kW to €1350/kW. As shown in Figure

III.1.1, the investment costs per kW were found to be

lowest in Denmark, and slightly higher in Greece and

The Netherlands. For the UK, Spain and Germany, the

costs in the data selection were found to be around

20–30 per cent higher than in Denmark. However, it

should be observed that Figure III.1.1 is based on

limited data, so the results might not be entirely representative

for the countries involved.

Also, for ‘other costs’, such as foundations and grid

connection, there is considerable variation between

countries, ranging from around 32 per cent of total

turbine costs in Portugal to 24 per cent in Germany,

21 per cent in Italy and only 16 per cent in Denmark.

However, costs vary depending on turbine size as well

as the country of installation.

The typical ranges of these other cost components

as a share of total additional costs are shown in

Table III.1.2. In terms of variation, the single most

important additional component is the cost of grid

connection, which, in some cases, can account for

almost half of the auxiliary costs, followed by typically

lower shares for foundation cost and the cost of

the electrical installation. Thus these auxiliary costs

may add significant amounts to the total cost of the

turbine. Cost components such as consultancy and

land usually only account for a minor share of the additional

costs.


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 201

Figure III.1.1: Total investment cost, including turbine, foundations and grid connection, shown for different turbine sizes and

countries of installation

1600

2006

1400

1200

€1000/MW

1000

800

600

400

200

0

Italy

UK

Netherlands

Portugal

Germany

Japan

Greece

Spain

Canada

Denmark

US

Norway

Source: Risø DTU; based on data from the IEA

For a number of selected countries, the turbine and

auxiliary costs (foundations and grid connection) are

shown in Figure III.1.2.

Table III.1.2: Cost structure for a medium-sized wind

turbine

Share of total

cost (%)

Typical share of

other costs (%)

Turbine (ex-works) 68–84 n/a

Foundation 1–9 20–25

Electric installation 1–9 10–15

Grid connection 2–10 35–45

Consultancy 1–3 5–10

Land 1–5 5–10

Financial costs 1–5 5–10

Road construction 1–5 5–10

Note: Based on a limited data selection from Germany, Denmark, Spain and the

UK, adjusted and updated by the author.

Source: Risø DTU

TRENDS INFLUENCING THE COSTS

OF WIND POWER

In recent years, three major trends have dominated

the development of grid-connected wind turbines:

1. Turbines have become larger and taller – the average

size of turbines sold on the market has increased

substantially.

2. The efficiency of turbine production has increased

steadily.

3. In general, the investment costs per kW have

decreased, although there has been a deviation

from this trend in recent years.

Figure III.1.3 shows the development of the averagesized

wind turbine for a number of the most important

wind power countries. It can be observed that the annual

average size has increased significantly over the last

10–15 years, from approximately 200 kW in 1990 to


202 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.1.2: Price of turbine and additional costs for

foundation and grid connection, calculated per kW for

selected countries (left axis), including turbine share of

total costs (right axis)

€/kW

1200

1000

800

600

400

200

0

Italy

Portugal

Germany

Japan

Denmark

100

Price of turbine per kW

Other costs per kW

Turbine share of total costs

Note: The result for Japan may be caused by a different split of turbine investment

costs and other costs, as the total adds up to almost the same level as seen for the

other countries.

Source: Risø DTU

2 MW in 2007 in the UK, with Germany, Spain and the

US not far behind.

As shown, there is a significant difference between

some countries: in India, the average installed size in

2007 was around 1 MW, considerably lower than levels

in the UK and Germany (2049 kW and 1879 kW respectively).

The unstable picture for Denmark in recent

years is due to the low level of turbine installations.

In 2007, turbines of the MW class (with a capacity of

over 1 MW) had a market share of more than 95 per

cent, leaving less than 5 per cent for the smaller

machines. Within the MW segment, turbines with capacities

of 2.5 MW and upwards are becoming increasingly

important, even for on-land sites. In 2007, the

US

Norway

90

80

70

60

50

40

30

20

10

0

Turbine share of total costs %

market share of these large turbines was 6 per cent,

compared to only 0.3 per cent at the end of 2003.

The wind regime at the chosen site, the turbine hub

height and the efficiency of production determine

power production from the turbines. So just increasing

the height of turbines has resulted in higher power

production. Similarly, the methods for measuring and

evaluating the wind speed at a given site have improved

substantially in recent years and thus improved the

site selection for new turbines. However, the fast

development of wind power capacity in countries such

as Germany and Denmark implies that the best wind

sites in these countries have already been taken and

that new on-land turbine capacity will have to be

erected at sites with a marginally lower average wind

speed. The replacement of older and smaller turbines

with modern versions is also becoming increasingly

important, especially in countries which have been

involved in wind power development for a long time, as

is the case for Germany and Denmark.

The development of electricity production efficiency,

owing to better equipment design, measured as annual

energy production per square metre of swept rotor

area (kWh/m 2 ) at a specific reference site, has correspondingly

improved significantly in recent years.

With improved equipment efficiency, improved turbine

siting and higher hub height, the overall production

efficiency has increased by 2–3 per cent annually over

the last 15 years.

Figure III.1.4 shows how these trends have affected

investment costs, exemplified by the case of Denmark,

from 1989 to 2006. The data reflects turbines installed

in the particular year shown (all costs are converted to

2006 prices); all costs on the right axis are calculated

per square metre of swept rotor area, while those on

the left axis are calculated per kW of rated capacity.

The number of square metres covered by the turbine’s

rotor – the swept rotor area – is a good indicator

of the turbine’s power production, so this measure is a

relevant index for the development in costs per kWh.

As shown in Figure III.1.4, there was a substantial


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 203

Figure III.1.3: Development of the average wind turbine size sold in different countries

2500

2000

1500

Germany

Spain

Denmark

US

UK

India

1000

500

0

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

Source: BTM-Consult

Figure III.1.4: The development of investment costs from 1989 to 2006, illustrated by the case of Denmark

1200

600

€/kW

1000

800

600

400

150 kW 225 kW

300 kW

500 kW

600 kW

1000 kW

2000 kW

500

400

300

200

€ per swept rotor area

Price of turbine per kW

Other costs per kW

Total cost per swept m 2

200

100

0

1989 1991 1993 1995 1997 2001 2004 2006

Year of installation

0

Note: Right axis – investment costs divided by swept rotor area (€/m 2 in constant 2006-€); Left axis – wind turbine capital costs (ex-works) and other costs per kW rated power

(€/kW in constant 2006-€).


204 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

decline in costs per unit of swept rotor area in the

period under consideration, except during 2006. From

the late 1980s until 2004, overall investments per unit

of swept rotor area declined by more than 2 per cent

per annum, corresponding to a total reduction in cost

of almost 30 per cent over these 15 years. But this

trend was broken in 2006, when total investment costs

rose by approximately 20 per cent compared to 2004,

mainly due to a significant increase in demand for wind

turbines, combined with rising commodity prices and

supply constraints.

Looking at the cost per rated capacity (per kW), the

same decline is found in the period 1989 to 2004, with

the exception of the 1000 kW machine in 2001. The

reason for this exception is related to the size of this

particular turbine: with a higher hub height and larger

rotor diameter, the turbine is equipped with a slightly

smaller generator, although it produces more electricity.

This fact is particularly important when analysing

turbines built specifically for low and medium wind

areas, where the rotor diameter is considerably larger

in comparison to the rated capacity. As shown in

Figure III.1.4, the cost per kW installed also rose by

20 per cent in 2006 compared to 2004.

In addition, the share of other costs as a percentage

of total costs has generally decreased. In 1989, almost

29 per cent of total investment costs were related to

costs other than the turbine itself. By 1997, this share

had declined to approximately 20 per cent. This trend

towards lower auxiliary costs continues for the last

turbine model shown (2000 kW), where other costs

amount to approximately 18 per cent of total costs.

But from 2004 to 2006 other costs rose almost in

parallel with the cost of the turbine itself.

The recent increase in turbine prices is a global

phenomenon which stems mainly from a strong and

increasing demand for wind power in many countries,

along with constraints on the supply side (not only

related to turbine manufacturers, but also resulting

from a deficit in sub-supplier production capacity of

wind turbine components). The general price increases

for newly installed wind turbines in a number of selected

countries are shown in Figure III.1.5. There are significant

differences between individual countries, with

price increases ranging from almost none to a rise of

more than 40 per cent in the US and Canada.

Operation and Maintenance Costs

of Wind-Generated Power

Operation and maintenance (O&M) costs constitute a

sizeable share of the total annual costs of a wind turbine.

For a new turbine, O&M costs may easily make

up 20–25 per cent of the total levelised cost per kWh

produced over the lifetime of the turbine. If the turbine

is fairly new, the share may only be 10–15 per cent,

but this may increase to at least 20–35 per cent by the

end of the turbine’s lifetime. As a result, O&M costs are

attracting greater attention, as manufacturers attempt

to lower these costs significantly by developing new

turbine designs that require fewer regular service

visits and less turbine downtime.

O&M costs are related to a limited number of cost

components, including:

• insurance;

• regular maintenance;

• repair;

• spare parts; and

• administration.

Some of these cost components can be estimated

relatively easily. For insurance and regular maintenance,

it is possible to obtain standard contracts covering

a considerable share of the wind turbine’s total

lifetime. Conversely, costs for repairs and related

spare parts are much more difficult to predict. And

although all cost components tend to increase as the

turbine gets older, costs for repair and spare parts are

particularly influenced by turbine age, starting low and

increasing over time.

Due to the relative infancy of the wind energy industry,

there are only a few turbines that have reached


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 205

Figure III.1.5: The increase in turbine prices from 2004 to 2006 for selected countries

1600

1400

2006

2004

1200

1000

€/kW

800

600

400

200

0

Denmark

Greece

Netherlands

US

Portugal

Italy

Japan

Norway

Spain

UK

Germany

Canada

Note: Preliminary data shows that prices for new turbines might continue to rise during 2007.

Source: IEA (2007b)

their life expectancy of 20 years. These turbines are

much smaller than those currently available on the

market. Estimates of O&M costs are still highly unpredictable,

especially around the end of a turbine’s lifetime;

nevertheless a certain amount of experience

can be drawn from existing older turbines.

Based on experiences in Germany, Spain, the UK

and Denmark, O&M costs are generally estimated to

be around 1.2 to 1.5 euro cents (c€) per kWh of wind

power produced over the total lifetime of a turbine.

Spanish data indicates that less than 60 per cent of

this amount goes strictly to the O&M of the turbine

and installations, with the rest equally distributed

between labour costs and spare parts. The remaining

40 per cent is split equally between insurance, land

rental 2 and overheads.

Figure III.1.6 shows how total O&M costs for the

period between 1997 and 2001 were split into six different

categories, based on German data from DEWI.

Expenses pertaining to buying power from the grid and

land rental (as in Spain) are included in the O&M costs

calculated for Germany. For the first two years of its

lifetime, a turbine is usually covered by the manufacturer’s

warranty, so in the German study O&M costs

made up a small percentage (2–3 per cent) of total

investment costs for these two years, corresponding

to approximately 0.3–0.4c€/kWh. After six years, the

total O&M costs increased, constituting slightly less

than 5 per cent of total investment costs, which is

equivalent to around 0.6–0.7c€/kWh. These figures

are fairly similar to the O&M costs calculated for newer

Danish turbines (see below).

Figure III.1.7 shows the total O&M costs resulting from

a Danish study and how these are distributed between

the different O&M categories, depending on the type,

size and age of the turbine. For a three-year-old 600 kW

machine, which was fairly well represented in the

study, 3 approximately 35 per cent of total O&M costs


206 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.1.6: Different categories of O&M costs for German

turbines, averaged for 1997–2001

Administration

21%

Source: DEWI

Land rent

18%

Power from

the grid

5%

Miscellaneous

17%

Insurance

13%

Service and

spare parts

26%

covered insurance, 28 per cent regular servicing,

11 per cent administration, 12 per cent repairs and

spare parts, and 14 per cent other purposes. In general,

the study revealed that expenses for insurance,

regular servicing and administration were fairly stable

over time, while the costs for repairs and spare parts

fluctuated considerably. In most cases, other costs

were of minor importance.

Figure III.1.7 also shows the trend towards lower

O&M costs for new and larger machines. So for a

three-year-old turbine, the O&M costs decreased from

around 3.5c€/kWh for the old 55 kW turbines to less

than 1c€/kWh for the newer 600 kW machines.

The figures for the 150 kW turbines are similar to the

O&M costs identified in the three countries mentioned

above. Moreover, Figure III.1.7 shows clearly that

O&M costs increase with the age of the turbine.

Figure III.1.7: O&M costs as reported for selected types and ages of turbines

5.0

4.5

4.0

3.5

Other costs

Insurance

Administration

Repair

Service

3.0

c€/kWh

2.5

2.0

1.5

1.0

0.5

0

3

years old

3

years old

3

years old

10

years old

10

years old

15

years old

55 kW

150 kW

600 kW 55 kW 150 kW

55 kW

Source: Jensen et al. (2002)


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 207

With regard to the future development of O&M

costs, care must be taken in interpreting the results of

Figure III.1.7. First, as wind turbines exhibit economies

of scale in terms of declining investment costs

per kW with increasing turbine capacity, similar economies

of scale may exist for O&M costs. This means

that a decrease in O&M costs will be related, to a

certain extent, to turbine up-scaling. And second, the

newer and larger turbines are better aligned with

dimensioning criteria than older models, implying

reduced lifetime O&M requirements. However, this

may also have the adverse effect that these newer

turbines will not stand up as effectively to unexpected

events.

The Cost of Energy Generated

by Wind Power

• Investment costs reflect the range given in Chapter

III.2 – that is, a cost of €1100–1400/kW, with an

average of €1225/kW. These costs are based on

data from IEA and stated in 2006 prices.

• O&M costs are assumed to be 1.45c€/kWh as an

average over the lifetime of the turbine.

• The lifetime of the turbine is set at 20 years, in

accordance with most technical design criteria.

• The discount rate is assumed to range from 5 to

10 per cent per annum. In the basic calculations, a

discount rate of 7.5 per cent per annum is used,

although a sensitivity analysis of the importance of

this interest range is also performed.

• Economic analyses are carried out on a simple

national economic basis. Taxes, depreciation and

risk premiums are not taken into account and all

calculations are based on fixed 2006 prices.

The total cost per kWh produced (unit cost) is calculated

by discounting and levelising investment and

O&M costs over the lifetime of the turbine and then

dividing them by the annual electricity production.

The unit cost of generation is thus calculated as an

average cost over the turbine’s lifetime. In reality,

actual costs will be lower than the calculated average

at the beginning of the turbine’s life, due to low

O&M costs, and will increase over the period of

turbine use.

The turbine’s power production is the single most

important factor for the cost per unit of power generated.

The profitability of a turbine depends largely on

whether it is sited at a good wind location. In this

section, the cost of energy produced by wind power

will be calculated according to a number of basic

assumptions. Due to the importance of the turbine’s

power production, the sensitivity analysis will be

applied to this parameter. Other assumptions include

the following:

• Calculations relate to new land-based, mediumsized

turbines (1.5–2 MW) that could be erected

today.

The calculated costs per kWh of wind-generated

power, as a function of the wind regime at the chosen

sites, are shown in Figure III.1.8. As illustrated, the

costs range from approximately 7–10c€/kWh at sites

with low average wind speeds to approximately 5–

6.5c€/kWh at windy coastal sites, with an average

of approximately 7c€/kWh at a wind site with average

wind speeds.

In Europe, the good coastal positions are located

mainly in the UK, Ireland, France, Denmark and Norway.

Medium wind areas are mostly found inland in mid

and southern Europe – in Germany, France, Spain, The

Netherlands and Italy – and also in northern Europe –

in Sweden, Finland and Denmark. In many cases, local

conditions significantly influence the average wind

speeds at a specific site, so significant fluctuations in

the wind regime are to be expected even for neighbouring

areas.

Approximately 75–80 per cent of total power production

costs for a wind turbine are related to capital

costs – that is, the costs of the turbine, foundations,

electrical equipment and grid connection. Thus a

wind turbine is capital-intensive compared with


208 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.1.8: Calculated costs per kWh of wind-generated power as a function of the wind regime at the chosen site (number

of full load hours)

12.00

10.00

€1100/kW

€1400/kW

8.00

c€/kWh

6.00

4.00

2.00

0.00

Low wind areas

Medium wind areas

Coastal areas

1500 1700 1900 2100 2300 2500 2700 2900

Note: In this figure, the number of full load hours is used to represent the wind regime. Full load hours are calculated as the turbine’s average annual production divided by its

rated power. The higher the number of full load hours, the higher the wind turbine’s production at the chosen site.

Source: Risø DTU

conventional fossil fuel-fired technologies, such as

natural gas power plants, where as much as 40–60

per cent of total costs are related to fuel and O&M

costs. For this reason, the costs of capital (discount

or interest rate) are an important factor for the cost

of wind-generated power, a factor which varies considerably

between the EU member countries.

In Figure III.1.9, the costs per kWh of wind-produced

power are shown as a function of the wind regime and

the discount rate (which varies between 5 and 10 per

cent per annum).

As illustrated in Figure III.1.9, the costs range

between around 6 and 8c€/kWh at medium wind

positions, indicating that a doubling of the interest

rate induces an increase in production costs of

2c€/kWh. In low wind areas, the costs are significantly

higher, at around 8–11c€/kWh, while the

production costs range between 5 and 7c€/kWh in

coastal areas.

Development of the Cost of

Wind-Generated Power

The rapid European and global development of wind

power capacity has had a strong influence on the

cost of wind power over the last 20 years. To illustrate

the trend towards lower production costs of windgenerated

power, a case that shows the production

costs for different sizes and models of turbines is

presented in Figure III.1.10.

Figure III.1.10 shows the calculated unit cost for

different sizes of turbine, based on the same assumptions

used in the previous section: a 20-year lifetime is

assumed for all turbines in the analysis and a real

discount rate of 7.5 per cent per annum is used. All

costs are converted into constant 2006 prices. Turbine

electricity production is estimated for two wind

regimes – a coastal and an inland medium wind

position.


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 209

Figure III.1.9: The costs of wind-produced power as a function of wind speed (number of full load hours) and discount rate; the

installed cost of wind turbines is assumed to be €1225/kW

12.00

10.00

5% p.a.

7.5% p.a.

10% p.a.

8.00

c€/kWh

6.00

4.00

2.00

0.00

Low wind areas

Medium wind areas

Coastal areas

1500 1700 1900 2100 2300 2500 2700 2900

Number of full load hours per year

Source: Risø DTU

The starting point for the analysis is the 95 kW

machine, which was installed mainly in Denmark during

the mid-1980s. This is followed by successively

newer turbines (150 kW and 225 kW), ending with the

2000 kW turbine, which was typically installed from

around 2003 onwards. It should be noted that wind

turbine manufacturers generally expect the production

cost of wind power to decline by 3–5 per cent for each

new turbine generation they add to their product portfolio.

The calculations are performed for the total lifetime

(20 years) of the turbines; calculations for the

old turbines are based on track records of more than

15 years (average figures), while newer turbines may

have a track record of only a few years, so the newer

the turbine, the less accurate the calculations.

The economic consequences of the trend towards

larger turbines and improved cost-effectiveness are

clearly shown in Figure III.1.10. For a coastal position,

for example, the average cost has decreased from around

9.2c€/kWh for the 95 kW turbine (mainly installed in

the mid-1980s) to around 5.3c€/kWh for a fairly

new 2000 kW machine, an improvement of more than

40 per cent over 20 years (constant 2006 prices).

Future Evolution of the Costs of

Wind-Generated Power

In this section, the future development of the economics

of wind power is illustrated by the use of the

experience curve methodology. The experience curve

approach was developed in the 1970s by the Boston

Consulting Group; it relates the cumulative quantitative

development of a product to the development

of the specific costs (Johnson, 1984). Thus, if the

cumulative sale of a product doubles, the estimated

learning rate gives the achieved reduction in specific

product costs.

The experience curve is not a forecasting tool based

on estimated relationships. It merely shows the development

as it would be if existing trends continue.


210 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.1.10: Total wind energy costs per unit of electricity produced, by turbine size (c€/kWh, constant 2006 prices)

12

10

Coastal site

Inland site

8

c€/kWh

6

4

2

0

95 150 225 300 500 600 1000 2000

year 2004

kW

2000

year 2006

Source: Risø DTU

It converts the effect of mass production into an effect

upon production costs, without taking other causal

relationships into account. Thus changes in market

development and/or technological breakthroughs

within the field may change the picture considerably,

as would fluctuations in commodity prices such as

those for steel and copper.

Different experience curves have been estimated 4

for a number of projects. Unfortunately, different specifications

were used, which means that not all of

these projects can be directly compared. To obtain the

full value of the experiences gained, the reduction in

price of the turbine (€/kW) should be taken into

account, as well as improvements in the efficiency of

the turbine’s production (which requires the use of an

energy specification (€/kWh); see Neij et al., 2003).

Thus, using the specific costs of energy as a basis

(costs per kWh produced), the estimated progress

ratios range from 0.83 to 0.91, corresponding to

learning rates of 0.17 to 0.09. So when the total

installed capacity of wind power doubles, the costs per

kWh produced for new turbines goes down by between

9 and 17 per cent. In this way, both the efficiency

improvements and embodied and disembodied cost

reductions are taken into account in the analysis.

Wind power capacity has developed very rapidly in

recent years, on average by 25 to 30 per cent per year

over the last ten years. At present, the total wind

power capacity doubles approximately every three to

four years. Figure III.1.11 shows the consequences for

wind power production costs, based on the following

assumptions:

• The present price-relation should be retained until

2010. The reason why no price reductions are

foreseen in this period is due to a persistently high

demand for new wind turbine capacity and subsupplier

constraints in the delivery of turbine

components.


WIND ENERGY - THE FACTS - COST OF ON-LAND WIND POWER 211

Figure III.1.11: Using experience curves to illustrate the future development of wind turbine economics until 2015

12

10

Inland site

8

c€/kWh

6

Coastal area

4

2

0

1985 1987 1990 1993 1996 1999 2001 2004 2006 2010 2015

Note: Costs are illustrated for an average 2 MW turbine installed at either an inland site or a coastal site.

Source: Risø DTU

• From 2010 until 2015, a learning rate of 10 per cent

is assumed, implying that each time the total

installed capacity doubles, the costs per kWh of

wind generated power decrease by 10 per cent.

• The growth rate of installed capacity is assumed to

double cumulative installations every three years.

The curve illustrates cost development in Denmark,

which is a fairly cheap wind power country. Thus the

starting point for the development is a cost of wind

power of around 6.1c€/kWh for an average 2 MW turbine

sited at a medium wind regime area (average

wind speed of 6.3 m/s at a hub height of 50 m). The

development for a coastal position is also shown.

At present, the production costs for a 2 MW wind

turbine installed in an area with a medium wind

speed (inland position) are around 6.1c€/kWh of

wind-produced power. If sited in a coastal location,

the current costs are around 5.3c€/kWh. If a doubling

time of total installed capacity of three years is

assumed, in 2015 the cost interval would be approximately

4.3 to 5.0c€/kWh for a coastal and inland

site respectively. A doubling time of five years would

imply a cost interval, in 2015, of 4.8 to 5.5c€/kWh.

As mentioned, Denmark is a fairly cheap wind

power country; for more expensive countries, the

cost of wind power produced would increase by

1–2c€/kWh.


III.2

OFFSHORE DEVELOPMENTS

Development and Investment Costs

of Offshore Wind Power

Offshore wind only accounts for a small amount of the

total installed wind power capacity in the world –

approximately 1 per cent. The development of offshore

wind has mainly been in northern European

countries, around the North Sea and the Baltic Sea,

where about 20 projects have been implemented. At

the end of 2007, almost 1100 MW of capacity was

located offshore.

Five countries have operating offshore wind farms:

Denmark, Ireland, The Netherlands, Sweden and the

UK, as shown in Table III.2.1. In 2007, the Swedish

offshore wind farm Lillgrunden, with a rated capacity

of 110 MW, was installed. Most of the capacity has

been installed in relatively shallow waters (under

20 m deep) no more than 20 km from the coast in

order to minimise the extra costs of foundations and

sea cables.

Offshore wind is still around 50 per cent more expensive

than onshore wind. However, due to the expected

benefits of more wind and the lower visual impact of

the larger turbines, several countries now have very

ambitious goals concerning offshore wind.

The total capacity is still limited, but growth rates

are high. Offshore wind farms are installed in large

units – often 100–200 MW – and two new installed

wind farms per year will result in future growth rates of

between 20 and 40 per cent. Presently, higher costs

and temporary capacity problems in the manufacturing

stages, as well as difficulties with the availability of

installation vessels, cause some delays, but even so,

several projects in the UK and Denmark will be finished

within the next three years, as can be seen in

Tables III.2.2–III.2.6.

Offshore costs depend largely on weather and wave

conditions, water depth and distance from the coast.

The most detailed cost information on recent offshore

installations comes from the UK, where 90 MW in

Figure III.2.1: Development of offshore wind power in the EU, 1998–2007

1000

800

Offshore wind market

development in the EU –

cumulative installation

Offshore wind market

development in the EU –

annual installation

MW

600

400

200

0

1998 1999 2000 2001 2002 2003 2004 2005 2006

2007

Source: EWEA


WIND ENERGY - THE FACTS - OFFSHORE DEVELOPMENTS 213

Figure III.2.2: Total offshore wind power installed by the

end of 2007

United

Kingdom

37%

Source: EWEA

404 MW

25 MW

108 MW

Ireland

2%

Netherlands

10%

133 MW

409 MW

Sweden

12%

Denmark

39%

2006 and 100 MW in 2007 were added, and from

Sweden with the installation of Lillgrunden in 2007.

Table III.2.7 gives information on some of the recently

established offshore wind farms. As shown, the chosen

turbine size for offshore wind farms ranges from 2 to

3.6 MW, with the newer wind farms being equipped

with the larger turbines. The size of the wind farms also

vary substantially, from the fairly small Samsø wind

farm of 23 MW to Robin Rigg, the world’s largest

offshore wind farm, with a rated capacity of 180 MW.

Investment costs per MW range from a low of €1.2

million/MW (Middelgrunden) to €2.7 million/MW

(Robin Rigg) (Figure III.2.3).

The higher offshore capital costs are due to the larger

structures and the complex logistics of installing the

towers. The costs of offshore foundations, construction,

installations and grid connection are significantly

higher than for onshore. For example, offshore turbines

are generally 20 per cent more expensive and towers

and foundations cost more than 2.5 times the price of

those for a similar onshore project.

In general, the costs of offshore capacity have

increased in recent years, as is the case for landbased

turbines, and these increases are only partly

reflected in the costs shown in Figure III.2.3. As a

result, the average costs of future offshore farms are

expected to be higher. On average, investment costs

for a new offshore wind farm are expected be in

the range of €2.0–2.2 million/MW for a near-shore,

shallow-water facility.

To illustrate the economics of offshore wind turbines

in more detail, the two largest Danish offshore wind

farms can be taken as examples. The Horns Rev project,

located approximately 15 km off the west coast of

Jutland (west of Esbjerg), was finished in 2002. It is

equipped with 80 machines of 2 MW, with a total capacity

of 160 MW. The Nysted offshore wind farm is located

south of the isle of Lolland. It consists of 72 turbines of

2.3 MW and has a total capacity of 165 MW. Both wind

farms have their own on-site transformer stations,

Table III.2.1: Installed offshore capacity in offshore wind countries

Country MW installed in 2006 Accumulated MW, end 2006 MW installed in 2007 Accumulated MW, end 2007

Denmark 0 409 0 409

Ireland 0 25 0 25

The Netherlands 108 108 0 108

Sweden 0 23 110 133

UK 90 304 100 404

Total global 198 869 210 1079

Source: EWEA


214 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.2.2: Operating and planned offshore wind farms in the UK

Project Location Region

Capacity

(MW)

No of

turbines

Water

depth (m)

Distance

to shore

(km)

Online

In operation

Barrow 7 km from Walney Island Off England 90 30 >15 7 2006

Beatrice Beatrice Oilfield, Moray Firth Off Scotland 10 2 >40 unknown 2007

Blyth Offshore 1 km from Blyth Harbour Off England 3.8 2 6 1 2000

Burbo Bank 5.2 km from Crosby Off England 90 25 10 5.2 2007

Inner Dowsing 5.2 km from Ingoldmells Off England 90 30 10 5.2 2008

Kentish Flats 8.5 km from Whitstable Off England 90 30 5 8.5 2005

Lynn 5.2 km from Skegness Off England 97 30 10 5.2 2008

North Hoyle 7.5 km from Prestatyn and Rhyl Off Wales/England 60 30 5–12 7.5 2003

Scroby Sands 3 km NE of Great Yarmouth Off England 60 30 2–10 3 2004

403.8

Under construction

Greater Gabbard phase 1 Off Felixstowe/Clacton-on-Sea Off England 300 - - - 2010

Greater Gabbard phase 2 Off Felixstowe/Clacton-on-Sea Off England 200 - - - 2011

Ormonde Off Walney Island Off England 150 30 20 11 2010

Rhyl Flats 8 km from Abergele Off Wales 90 25 8 8 2009

Solway Firth/

Robin Rigg A

9.5 km from Maryport/8.5 km

off Rock Cliffe

Off England/

Scotland

90 30 >5 9.5 2010

Solway Firth/

Robin Rigg B

9.5 km from Maryport/8.5 km

off Rock Cliffe

Off England/

Scotland

90 30 >5 9.5 2010

Thanet Foreness Point, Margate Off England 300 100 20–25 7–8.5 2010

Source: EWEA

Table III.2.3: Operating and planned offshore wind farms in The Netherlands

Project Location Capacity (MW) No of turbines Water depth (m) Distance to shore (km) Online

In operation

Offshore Wind Farm

Egmond aan Zee (OWEZ)

Egmond aan Zee 108 36 17–23 8–12 2006

Lely

Irene Vorrink (Dronten)

Medemblik, Ijsselmeer

(inland lake)

Dronten, Ijsselmeer

(inland freshwater lake),

to the outside of the dyke

2 4 7.5 0.75 1994

16.8 28 2 0.03 1996

Princess Amalia Ijmuiden 120 60 19–24 > 23 2008

Source: EWEA


WIND ENERGY - THE FACTS - OFFSHORE DEVELOPMENTS 215

Table III.2.4: Operating and planned offshore wind farms in Denmark

Project

Location

Capacity

(MW)

No of

turbines

Water

depth (m)

Distance to

shore (km)

Online

In operation

Vindeby Blæsenborg Odde, NW off Vindeby, Lolland 4.95 11 2.5–5 2.5 1991

TunøKnob off Aarhus, Kattegat Sea 5 10 0.8–4 6 1995

Middelgrunden Oresund, east of Copenhagen harbour 40 20 5–10 2–3 2001

Horns Rev I Blåvandshuk, Baltic Sea 160 80 6–14 14–17 2002

Nysted Havmøllepark Rødsand, Lolland 165.6 72 6–10 6–10 2003

Samsø Paludans Flak, South of Samsø 23 4 11–18 3.5 2003

Frederikshavn Frederikshavn Harbour 10.6 4 3 0.8 2003

Rønland I

Under construction

Lim fjord, off Rønland peninsula, in the

Nissum Bredning, off NW Jutland

17.2 8 3 2003

426.35

Avedøre Off Avedøre 7.2 2 2 0.025 2009

Frederikshavn (test site) Frederikshavn Harbour 12 2 15–20 4.5 2010

Rødsand 2 Off Rødsand, Lolland 200 89 5–15 23 2010

Sprøgø North of Sprøgø 21 7 6–16 0.5 2009

Horns Rev II

Source: EWEA

Blåvandshuk, Baltic Sea (10 km west of

Horns Rev)

209 91 9–17 30 2010

Table III.2.5: Operating and planned offshore wind farms in Sweden

Project Location Capacity (MW) No of turbines Water depth (m) Distance to shore (km) Online

In operation

Bockstigen Gotland 2.8 5 6–8 3 1998

Utgrunden I Kalmarsund 10.5 7 4–10 7 2001

Yttre Stengrund Kalmarsund 10.0 5 8–12 4 2002

Lillgrund Malmö 110.0 48 2.5–9 10 2007

133.25

Under construction

Gässlingegrund Vänern 30 10 4–10 4 2009

Source: EWEA

Table III.2.6: Operating offshore wind farms in Ireland

Project Location Capacity (MW) No of turbines Water depth (m) Distance to shore (km) Online

Arklow Bank Off Arklow, Co Wicklow 25.2 7 15 10 2004

Source: EWEA


216 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.2.7: Key information on recent offshore wind farms

In operation

No of turbines

Turbine size

(MW)

Total capacity

(MW)

Investment costs

(€ million)

Middelgrunden (DK) 2001 20 2 40 47

Horns Rev I (DK) 2002 80 2 160 272

Samsø (DK) 2003 10 2.3 23 30

North Hoyle (UK) 2003 30 2 60 121

Nysted (DK) 2004 72 2.3 165 248

Scroby Sands (UK) 2004 30 2 60 121

Kentish Flats (UK) 2005 30 3 90 159

Barrows (UK) 2006 30 3 90 –

Burbo Bank (UK) 2007 24 3.6 90 181

Lillgrunden (S) 2007 48 2.3 110 197

Robin Rigg (UK) 60 3 180 492

Note: Robin Rigg is under construction.

Source: Risø DTU

Figure III.2.3: Investments in offshore wind farms, €million/MW (current prices)

3.0

2.5

€ million/MW

2.0

1.5

1.0

0.5

0

Middelgrunden

Horns Rev I

Samsø

North Hoyle

Nysted

Scroby Sands

Kentish Flats

Burbo

Lillgrunden

Robin Rigg

Source: Risø DTU


WIND ENERGY - THE FACTS - OFFSHORE DEVELOPMENTS 217

Table III.2.8: Average investment costs per MW related to offshore wind farms in Horns Rev and Nysted

Investments (€1000 /MW) Share (%)

Turbines ex-works, including transport and erection 815 49

Transformer station and main cable to coast 270 16

Internal grid between turbines 85 5

Foundations 350 21

Design and project management 100 6

Environmental analysis 50 3

Miscellaneous 10


218 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.2.9: Assumptions used for economic calculations

In operation Capacity (MW) €million/MW Full load hours per year

Middelgrunden 2001 40 1.2 2500

Horns Rev I 2002 160 1.7 4200

Samsø 2003 23 1.3 3100

North Hoyle 2003 60 2.0 3600

Nysted 2004 165 1.5 3700

Scroby Sands 2004 60 2.0 3500

Kentish Flats 2005 90 1.8 3100

Burbo 2007 90 2.0 3550

Lillgrunden 2007 110 1.8 3000

Robin Rigg 180 2.7 3600

Note: Robin Rigg is under construction.

Source: Risø DTU

than 3000 full load hours per year. The investment and

production assumptions used to calculate the costs

per kWh are given in Table III.2.9.

In addition, the following economic assumptions are

made:

• Over the lifetime of the wind farm, annual O&M

costs are assumed to be €16 /MWh, except for

Middelgrunden, where these costs based on existing

accounts are assumed to be €12 /MWh for the

entire lifetime.

• The number of full load hours is given for a normal

wind year and corrected for shadow effects in the

farm, as well as unavailability and losses in transmission

to the coast.

• The balancing of the power production from the

turbines is normally the responsibility of the farm

owner. According to previous Danish experience,

balancing requires an equivalent cost of around

€3/MWh. 5 However, balancing costs are also uncertain

and may differ substantially between countries.

• The economic analyses are carried out on a simple

national economic basis, using a discount rate of

7.5 per cent per annum, over the assumed lifetime

of 20 years. Taxes, depreciation, profit and risk premiums

are not taken into account.

Figure III.2.4 shows the total calculated costs per

MWh for the wind farms listed in Table III.2.9.

It can be seen that total production costs differ significantly

between the illustrated wind farms, with Horns

Rev, Samsø and Nysted being among the cheapest and

Robin Rigg in the UK the most expensive. Differences

can be related partly to the depth of the sea and distance

to the shore and partly to increased investment

costs in recent years. O&M costs are assumed to be at

the same level for all wind farms (except Middelgrunden)

and are subject to considerable uncertainty.

Costs are calculated on a simple national economic

basis, and are not those of a private investor. Private

investors have higher financial costs and require a risk

premium and profit. So the amount a private investor

would add on top of the simple costs would depend, to

a large extent, on the perceived technological and

political risks of establishing the offshore farm and on

the competition between manufacturers and developers.

Development of the Cost of Offshore

Wind Power up to 2015

Until 2004, the cost of wind turbines generally

followed the development of a medium-term cost


WIND ENERGY - THE FACTS - OFFSHORE DEVELOPMENTS 219

Figure III.2.4: Calculated production cost for selected offshore wind farms, including balancing costs (2006 prices)

100

90

80

Balancing costs

O&M

Levelised investment

70

/MWh

60

50

40

30

20

10

0

Middelgrunden

Horns Rev

Samsø

North Hoyle

Nysted

Scroby Sands

Kentish Flats

Burbo

Lillgrunden

Robin Rigg

Source: Risø DTU

reduction curve (learning curve), showing a learning

rate of approximately 10 per cent – in other words,

each time wind power capacity doubled, the cost

went down by approximately 10 per cent per MW

installed. This decreasing cost trend changed in

2004–2006, when the price of wind power in general

increased by approximately 20–25 per cent. This was

caused mainly by the increasing costs of materials

and a strong demand for wind capacity, which implied

the scarcity of wind power manufacturing capacity

and sub-supplier capacity for manufacturing turbine

components.

A similar price increase can be observed for offshore

wind power, although the fairly small number

of finished projects, as well as a large spread in

investment costs, make it difficult to identify the

price level for offshore turbines accurately. On average,

the expected investment costs for a new offshore

wind farm are currently in the range of €2.0–

2.2 million/MW.

In the following section, the medium-term cost

development of offshore wind power is estimated using

the learning curve methodology. However, it should be

noted that considerable uncertainty is related to the

use of learning curves, even for the medium term, and

results should be used with caution.

The medium-term cost predictions for offshore wind

power are shown in Table III.2.10 under the following

conditions:

• The existing manufacturing capacity constraints for

wind turbines will continue until 2010. Although

there will be a gradual expansion of industrial capacity

for wind power, a prolonged increase in demand

will continue to strain the manufacturing capacity.

Increasing competition among wind turbine

manufacturers and sub-suppliers, resulting in unit

reduction costs in the industry, will not occur before

2011.

• The total capacity development of wind power is

assumed to be the main driving factor for the cost


220 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.2.10: Estimates for cost development of offshore wind turbines until 2015 (constant 2006 euros)

Investment costs, €million/MW O&M Capacity factor

Min Average Max €/MWh %

2006 1.8 2.1 2.4 16 37.5

2015 1.55 1.81 2.06 13 37.5

development of offshore turbines, since most of the

turbine costs are related to the general wind power

industry development. The growth rate of installed

capacity is assumed to double cumulative installations

every three years.

• For the period between 1985 and 2004, a learning

rate of approximately 10 per cent was estimated

(Neij et al., 2003). In 2011, this learning rate is

again expected to be achieved by the industry and

remain until at least 2015.

savings can be achieved if turbines are made of lighter,

more reliable materials and if major components are

developed to be more fatigue-resistant. A model based

on 2006 costs predicted that costs would rise from

approximately £1.6 million/MW to approximately

£1.75 million/MW (€2.37 to 2.6 million/MW) in 2011

before falling by around 20 per cent of the total cost

by 2020.

Given these assumptions, minimum, average and

maximum cost scenarios are reported in Table III.2.10.

As shown in Table III.2.10, the average cost of

offshore wind capacity is expected to decrease

from €2.1 million/MW in 2006 to €1.81 million/MW in

2015, or by approximately 15 per cent. There will still

be a considerable spread of costs, from €1.55 million/

MW to €2.06 million/MW. A capacity factor of a constant

37.5 per cent (corresponding to an approximate

number of full load hours of 3300) is expected for the

whole period. This covers increased production from

newer and larger turbines, moderated by sites with

lower wind regimes and a greater distance to shore,

which increase losses in transmission of power.

A study carried out in the UK (IEA, 2006) has estimated

the future costs of offshore wind generation

and the potential for cost reductions. The cost of raw

materials, especially steel, which accounts for about

90 per cent of the turbine, was identified as the primary

cost driver. The report emphasised that major


III.3

PROJECT FINANCING

Over the last couple of decades, the vast majority of

commercial wind farms have been funded through

project finance. Project finance is essentially a project

loan, backed by the cash flow of the specific project.

The predictable nature of cash flows from a wind farm

means they are highly suited to this type of investment

mechanism.

Recently, as an increasing number of large companies

have become involved in the sector, there has

been a move towards balance sheet funding, mainly

for construction. This means that the owner of the

project provides all the necessary financing for the

project, and the project’s assets and liabilities are all

directly accounted for at company level. At a later

date, these larger companies will sometimes group

multiple balance sheet projects in a single portfolio

and arrange for a loan to cover the entire portfolio, as

it is easier to raise a loan for the portfolio than for

each individual project.

The structured finance markets (such as bond

markets) in Europe and North America have also been

used, but to a more limited extent than traditional

project finance transactions. Such deals are like a

loan transaction insomuch as they provide the project

with an investment, in return for capital repayment

and interest. However, the way in which transactions

are set up is quite different to a traditional loan.

Different types of funding for renewable energy have

emerged in recent years in the structured debt market,

which has significantly increased the liquidity in

the sector.

Typical structures and transaction terms are discussed

in more detail in this chapter.

Traditional Methods

WHAT IS PROJECT FINANCE?

Project finance is the term used to describe a structure

in which the only security for a loan is the project

itself. In other words, the owner of the project company

is not personally, or corporately, liable for the loan.

In a project finance deal, no guarantee is given that

the loan will be repaid; however, if the loan is not

repaid, the investor can seize the project and run or

sell it in order to extract cash.

This process as rather like a giant property mortgage,

since if a homeowner does not repay the mortgage on

time, the house may be repossessed and sold by the

lender. Therefore, the financing of a project requires

careful consideration of all the different aspects, as well

as the associated legal and commercial arrangements.

Before investment, any project finance lender will want

to know if there is any risk that repayment will not be

made over the loan term.

DEAL STRUCTURE

A typical simple project finance deal will be arranged

through a special purpose vehicle (SPV) company. The

SPV is called ‘Wind Farm Ltd’ in Figure III.3.1. This

would be a separate legal entity which may be owned

by one company, consisting of several separate entities

or a joint venture.

One bank may act alone if the project is very small,

but will usually arrange a lending syndicate – this

means that a group of banks will join together to provide

the finance, usually with one bank as the ‘lead

arranger’ of the deal. This is shown in Figure III.3.1,

where Bank A syndicates the loan to Banks B, C

and D.

A considerable amount of work is carried out

before the loan is agreed, to check that the project

is well planned and that it can actually make the

necessary repayments by the required date. This process

is called ‘due diligence’, and there is usually

separate commercial, technical and legal due diligence

carried out on behalf of the bank. The investors

will make careful consideration of technical,

financial and political risks, as well as considering

how investment in a project fits in with the bank’s

own investment strategy.


222 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.3.1: Typical wind farm finance structure

Bank A

Bank B

Bank C

Equity investors

Owner Corp.

Bank D

Sale and purchase

agreement

Wind Farm Ltd

Banks

Finance

agreement

Construction contracts

Grid

PPA

O&M

Leases

Turbine

suppliers

Civil

contractor

Electrical

contractor

Grid operator

Utility

Turbine supplier

Landowners

Source: Garrard Hassan

TYPICAL DEAL PARAMETERS

Generally, a bank will not lend 100 per cent of the

project value and will expect to see a cash contribution

from the borrower – this is usually referred to as

‘equity’. It is typical to see 25–30 per cent equity and

70–75 per cent loan (money provided by the bank as

their investment). Occasionally, a loan of 80 per cent

is possible.

The size of the loan depends on the expected project

revenue, although it is typical for investors to take a

cautious approach and to assume that the long-term

income will be lower than assumed for normal operation.

This ensures that the loan does not immediately

run into problems in a year with poor wind conditions or

other technical problems, and also takes into account

the uncertainty associated with income prediction.

Typically, a bank will base the financial model on the

‘exceedance cases’ provided within the energy assessment

for the project. The mean estimated production of

the project (P50) may be used to decide on the size of

the loan, or in some cases a value lower than the mean

(for example P75 or P90). This depends on the level of

additional cash cushioning that is available to cover

costs and production variation over and above the

money that is needed to make the debt payments. This

is called the debt service cover ratio (DSCR) and is the

ratio of cash available at the payment date to the debt

service costs at that date. For example, if €1.4 million

is available to make a debt payment (repayment and

interest) of €1 million, the DSCR is 1.4:1.

The energy assumptions used for the financial model

and associated DSCR are always a matter of negotiation

with the bank as part of the loan agreement.

Some banks will take a very cautious approach to the

assumed energy production, with a low DCSR, and

some will assume a more uncertain energy case, but

with a high DSCR and sufficient cash cushioning to

cover potential production variation.

The loan is often divided into two parts: a construction

loan and a term loan. The construction loan provides

funds for the construction of the project and

becomes a term loan after completion. At the ‘conversion’

from a construction to a term loan, the terms and


WIND ENERGY - THE FACTS - PROJECT FINANCING 223

conditions associated with the loan change, as does

the pricing of the debt. The term loan is usually less

expensive than the construction loan, as the risks are

lower during operation.

Typically, the length of a loan is between 10 and 15

years, but loan terms have become longer as banks

have become more experienced in the wind industry.

The interest rate is often 1–1.5 per cent above the

base rate at which the bank borrows their own funds

(referred to as the interbank offer rate). In addition,

banks usually charge a loan set-up fee of around 1 per

cent of the loan cost, and they can make extra money by

offering administrative and account services associated

with the loan. Products to fix interest rates or foreign

exchange rates are often sold to the project owner.

It is also typical for investors to have a series of

requirements over the loan period; these are referred

to as ‘financial covenants’. These requirements are

often the result of the due diligence and are listed

within the ‘financing agreement’. Typical covenants

include the regular provision of information about operational

and financial reporting, insurance coverage,

and management of project bank accounts.

EXPERIENCE

there are some very particular structures that are

rather more complicated, as the US market is driven

by tax considerations.

The renewable energy incentive in the US is the

Production Tax Credit (PTC), and hence tax is of primary

rather than secondary importance. Since this

publication focuses on the European market, it is not

appropriate to describe the US approach in any detail,

but basically it includes another layer of ownership –

the tax investors – who own the vast majority of the

project, but only for a limited period of time (say ten

years), during which they can extract the tax advantage.

After that period there is an ownership ‘flip’, and

the project usually returns to its original owner. Many

sophisticated tax structures have been developed for

this purpose, and this characteristic has had a major

effect on the way in which the US industry has developed.

The owners of US wind farms tend to be large

companies with a heavy tax burden. Another group of

passive tax investors has also been created that does

not exist in the wind industry outside the US.

Recent Developments

STRUCTURED FINANCE

In the last two decades, no wind industry project has

ever had to be repossessed, although industry and project

events have triggered some restructuring to adjust

financing in difficult circumstances. The project finance

mechanism has therefore served the industry and the

banking community well. A decade ago, developers

might have struggled to find a bank ready to loan to a

project, whereas today banks often pursue developers

to solicit their loan requirements. Clearly, this has

improved the deals available to wind farm owners.

THE US

The description above covers most of the projectfinanced

loans arranged outside the US. Inside the US

The last five years has seen the emergence of a number

of new forms of transaction for wind financing,

including public and private bond or share issues.

Much of the interest in such structures has come from

renewable energy funds, long-term investors, such as

pension funds, and even high net worth individuals

seeking efficient investment vehicles. The principle

behind a structured finance product is similar to that

of a loan, being the investment of cash in return for

interest payment; however, the structures are generally

more varied than project finance loans. As a result,

there have been a number of relatively short-term

investments offered in the market, which have been

useful products for project owners considering project

refinancing after a few years of operation. Structured


224 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

finance investors have had a considerable appetite for

cross-border deals and have had a significant effect on

liquidity for wind (and other renewable energy) projects.

BALANCE SHEET FINANCING

The wind industry is becoming a utility industry in

which the major utilities are increasingly playing a big

role. As a result, while there are still many small projects

being developed and financed, an increasing number

are being built ‘on balance sheet’ (in other words with

the utility’s cash). Such an approach removes the need

for a construction loan and the financing consists of a

term loan only.

PORTFOLIO FINANCING

The arrival of balance sheet financing by the utilities

naturally creates ‘portfolio financing’, in which banks

are asked to finance a portfolio of wind farms rather

than a single one. These farms are often operational and

so data is available to allow for a far more accurate

projection of production. The portfolio will usually

include a range of projects separated by significant

physical distances, with a range of turbine types. The

use of different turbine types reduces the risk of widespread,

or at least simultaneous, design faults, and

the geographical spread ‘evens out the wind’. It is possible

to undertake a rigorous estimation of the way in

which the geographical spread reduces fluctuations

(Marco et al., 2007). Figure III.3.2 shows the averaging

effect of a portfolio of eight wind power plants in

three countries.

Finally, if the wind farms are in different countries,

then the portfolio also reduces regulatory risks.

The risk associated with such portfolio financing is

significantly lower than that of financing a single wind

farm before construction and attracts more favourable

terms. As a result, the interest in such financing is

growing. Portfolio financing can be adopted even after

the initial financing has been in place for some time.

It is now quite common to see an owner collecting

together a number of individually financed projects and

refinancing them as a portfolio.

Figure III.3.2: The geographical portfolio effect

Monthly wind speed

12.0

11.0

10.0

9.0

8.0

7.0

6.0

Portugal 1

Portugal 2

Portugal 3

Portugal 4

Portugal 5

Spain 1

Spain 2

France

Average

5.0

4.0

Feb 05

Source: Marco et al. (2007)

Mar 05 Apr 05 May 05 Jun 05 Jul 05 Aug 05 Sep 05 Oct 05 Nov 05 Dec 05 Jan 06 Feb 06

Month of the year


WIND ENERGY - THE FACTS - PROJECT FINANCING 225

TECHNOLOGY RISK

The present ‘sellers’ market’, characterised by the

shortage in supply of wind turbines, has introduced a

number of new turbine manufacturers, many of which

are not financially strong and none of which has a

substantial track record. Therefore, technology risk

remains a concern for the banks, and the old-fashioned

way of mitigating these risks, through extended warranties,

is resisted forcefully by both new and experienced

manufacturers. So technology risk has increased

recently, rather than diminishing over time. However,

some banks still show significant interest in lending to

projects that use technology with relatively little operational

experience.

OFFSHORE WIND

Offshore wind farms are now more common in

Europe. The first few projects were financed in the

way described above – by large companies with substantial

financial clout, using their own funds. The

initial involvement of banks was in the portfolio financing

of a collection of assets, one of which was an

offshore wind farm. Banks were concerned about the

additional risks associated with an offshore development,

and this approach allowed the risks to be diluted

somewhat.

Although there are still relatively few offshore wind

farms, banks are clearly interested in both term loans,

associated with the operational phase of offshore wind

farms, and the provision of construction finance. This

clearly demonstrates the banks’ appetite for wind

energy lending. It is too early to define typical offshore

financing, but it is likely to be more expensive than

that for the equivalent onshore farm, at least until the

banks gain greater confidence in the technology. The

risk of poor availability as a result of poor accessibility

is a particular concern.

BIG PROJECTS

Banks like big projects. The cost of the banks’ own

efforts and due diligence does not change significantly

with the project (loan) size, so big projects are more

attractive to them than smaller ones. Wind projects

are only now starting to be big enough to interest

some banks, so as project size increases, the banking

community available to support the projects will grow.

Furthermore, increasing project size brings more substantial

sponsors, which is also reassuring for banks.

CONCLUSIONS

The nature of wind energy deals is changing. Although

many small, privately owned projects remain, there

has been a substantial shift towards bigger, utilityowned

projects. This change brings new money to the

industry, reduces dependence on banks for initial funding

and brings strong sponsors.

Projects are growing and large-scale offshore activity

is increasing. Since banks favour larger projects,

this is a very positive change. If the general economic

picture deteriorates, this may give rise to certain

misgivings concerning project finance, in comparison

to the last few years, but political and environmental

support for renewable energy means that the funding

of wind energy remains a very attractive proposition.

Obtaining financing for the large-scale expansion of

the industry will not be a problem.


III.4

PRICES AND SUPPORT MECHANISMS

Introduction: Types of RES-E

Support Mechanism

When clustering the different types of support

mechanisms available to electricity from renewable

energy sources (RES-E), a fundamental distinction can

be made between direct and indirect policy instruments.

Direct policy measures aim to stimulate the

instal lation of RES-E technologies immediately,

whereas indirect instruments focus on improving longterm

framework conditions. Besides regulatory instruments,

voluntary approaches for the promotion of

RES-E technologies also exist, mainly based on consumers’

willingness to pay premium rates for green

electricity. Further important classification criteria

are whether policy instruments address price or

quantity, and whether they support investments or

generation.

Table III.4.1 provides a classification of the existing

promotional strategies for renewables; there follows

an explanation of the terminology used.

REGULATORY PRICE-DRIVEN STRATEGIES

Generators of RES-E receive financial support in

terms of a subsidy per kW of capacity installed, or a

payment per kWh produced and sold. The major

strategies are:

• investment-focused strategies: financial support is

given by investment subsidies, soft loans or tax credits

(usually per unit of generating capacity); and

• generation-based strategies: financial support is a

fixed regulated feed-in tariff (FIT) or a fixed premium

(in addition to the electricity price) that a

governmental institution, utility or supplier is legally

obligated to pay for renewable electricity from eligible

generators.

The difference between fixed FITs and premiums is

as follows: for fixed FITs, the total feed-in price is fixed;

for premium systems, the amount to be added to the

electricity price is fixed. For the renewable plant owner,

the total price received per kWh, in the premium scheme

(electricity price plus the premium), is less predictable

than under a feed-in tariff, since this depends on a

volatile electricity price.

In principle, a mechanism based on a fixed premium/

environmental bonus that reflects the external costs

of conventional power generation could establish

fair trade, fair competition and a level playing field

between RES and conventional power sources in

a competitive electricity market. From a market

Table III.4.1: Types of RES-E support mechanism

Direct

Price-driven Quantity-driven Indirect

Regulatory

Investment-focused

• Investment incentives

• Tax credits

• Low interest/Soft loans

• Tendering system for investment grant • Environmental taxes

• Simplification of authorisation

procedures

Generation-based

• (Fixed) feed-in tariffs

• Tendering system for long-term contracts

• Connection charges,

• Fixed premium system

Tradable Green Certificate system

balancing costs

Voluntary

Investment-focused

• Shareholder programmes

• Voluntary agreements

• Contribution programmes

Generation-based

• Green tariffs

Source: Ragwitz et al. (2007)


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 227

development perspective, the advantage of such a

scheme is that it allows renewables to penetrate the

market quickly if their production costs drop below the

electricity price plus premium. If the premium is set at

the ‘right’ level (theoretically at a level equal to the

external costs of conventional power), it allows renewables

to compete with conventional sources without

the need for governments to set ‘artificial’ quotas.

Together with taxing conventional power sources in

accordance with their environmental impact, welldesigned

fixed premium systems are theoretically the

most effective way of internalising external costs.

In practice, however, basing the mechanism on the

environmental benefits of renewables is challenging.

Ambitious studies, such as the European Commission’s

ExternE project, which investigates the external costs

of power generation, have been conducted in both

Europe and America; these suggest that establishing

exact costs is a complex matter. In reality, fixed premiums

for wind power and other renewable energy

technologies, such as the Spanish model, are based

on estimated production costs and are fixed based on

the electricity price, rather than on the environmental

benefits of RES.

REGULATORY QUANTITY-DRIVEN

STRATEGIES

The desired level of RES generation or market penetration

– a quota or a Renewable Portfolio Standard – is

defined by governments. The most important points are:

• Tendering or bidding systems: calls for tender are

launched for defined amounts of capacity. Competition

between bidders results in contract winners

that receive a guaranteed tariff for a specified

period of time.

• Tradable certificate systems: these systems are better

known in Europe as Tradable Green Certificate

(TCG) systems and in the US and Japan as Renewable

Portfolio Standards (RPSs). In such systems,

the generators (producers), wholesalers, distribution

companies or retailers (depending on who is

involved in the electricity supply chain) are obliged

to supply or purchase a certain percentage of

electricity from RES. At the date of settlement, they

have to submit the required number of certificates

to demonstrate compliance. Those involved may

obtain certificates:

• from their own renewable electricity generation;

• by purchasing renewable electricity and associated

certificates from another generator;

and/or

• by purchasing certificates without purchasing

the actual power from a generator or broker,

that is to say purchasing certificates that have

been traded independently of the power itself.

The price of the certificates is determined, in principle,

according to the market for these certificates

(for example NordPool).

VOLUNTARY APPROACHES

This type of strategy is mainly based on the willingness

of consumers to pay premium rates for renewable

energy, due to concerns over global warming, for

example. There are two main categories:

1. investment-focused: the most important are shareholder

programmes, donation projects and ethical

input; and

2. generation-based: green electricity tariffs, with and

without labelling.

INDIRECT STRATEGIES

Aside from strategies which directly address the promotion

of one (or more) specific renewable electricity

technologies, there are other strategies that may have

an indirect impact on the dissemination of renewables.

The most important are:

• eco-taxes on electricity produced with non-renewable

sources;


228 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

• taxes/permits on CO2 emissions; and

• the removal of subsidies previously given to fossil

and nuclear generation.

There are two options for the promotion of renewable

electricity via energy or environmental taxes:

1. exemption from taxes (such as energy and sulphur

taxes); and

2. if there is no exemption for RES, taxes can be

(partially or wholly) refunded.

Both measures make RES more competitive in the

market and are applicable for both established and

new plants.

Indirect strategies also include the institutional promotion

of the deployment of RES plants, such as site

planning and easy connection to the grid, and the operational

conditions of feeding electricity into the system.

First, siting and planning requirements can reduce

the potential opposition to RES-E plants if they address

issues of concern, such as noise and visual or environmental

impacts. Laws can be used to, for example, set

aside specific locations for development and/or omit

areas that are particularly open to environmental damage

or injury to birds.

Second, complementary measures also concern the

standardisation of economic and technical connection

conditions. Interconnection requirements are often

unnecessarily onerous and inconsistent and can lead to

high transaction costs for project developers, particularly

if they need to hire technical and legal experts. Safety

requirements are essential, particularly in the case of

interconnection in weak parts of the grid. However,

unclear criteria on interconnections can potentially lead

to higher prices for access to the grid and use of transmission

lines, or even unreasonable rejections of transmission

access. Therefore, it is recommended that

authorities clarify the safety requirements and the rules

on the burden of additional expenses.

Finally, rules must be established to govern the

responsibility for physical balancing associated with

some technologies’ variable production, in particular

for wind power.

COMPARISON OF PRICE-DRIVEN VERSUS

QUANTITY-DRIVEN INSTRUMENTS

In the following section, an assessment of direct promotional

strategies is carried out by focusing on the

comparison between price-driven (for example FITs,

investment incentives and tax credits) and quantitydriven

(for example Tradable Green Certificate (TGC)-

based quotas and tendering systems) strategies. The

different instruments can be described as follows:

• Feed-in tariffs (FITs) are generation-based, pricedriven

incentives. The price per unit of electricity

that a utility, supplier or grid operator is legally

obliged to pay for electricity from RES-E producers

is determined by this system. Thus a federal

(or provincial) government regulates the tariff

rate. It usually takes the form of either a fixed

price to be paid for RES-E production or an additional

premium on top of the electricity market

price paid to RES-E producers. Besides the level

of the tariff, its guaranteed duration represents

an important parameter for an appraisal of the

actual financial incentive. FITs allow technologyspecific

promotion, as well as an acknowledgement

of future cost reductions by applying dynamic

decreasing tariffs.

• Quota obligations based on Tradable Green Certificates

(TGCs) are generation-based, quantitydriven

instruments. The government defines

targets for RES-E deployment and requires a particular

party in the electricity supply chain (for

example the generator, wholesaler or consumer)

to fulfil certain obligations. Once defined, a parallel

market for renewable energy certificates is

established and their price is set following demand

and supply conditions (forced by the obligation).

Hence for RES-E producers, financial support may

arise from selling certificates, in addition to the


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 229

revenues from selling electricity on the power

market. Technology-specific promotion in TGC systems,

is also possible in principle. However, market

separation for different technologies would

lead to much smaller and less liquid markets. One

solution could be to weight certificates from different

technologies, but the key dilemma is how to

find weights that are correct or at least widely

accepted as fair.

• Tendering systems are quantity-driven mechanisms.

Financial support can either be investment-focused

or generation-based. In the first case, a fixed

amount of capacity to be installed is announced

and contracts are given following a predefined bidding

process, which offers winners a set of favourable

investment conditions, including investment

grants per kW installed. The generation-based tendering

systems work in a similar way; but instead of

providing up-front support, they offer support in the

form of a ‘bid price’ per kWh for a guaranteed

duration.

• Investment incentives are price-driven instruments

that establish an incentive for the development of

RES-E projects as a percentage of total costs, or

as a predefined amount of money per kW installed.

The level of these incentives is usually technologyspecific.

• Production tax incentives are also price-driven,

generation-based mechanisms that work through

payment exemptions from the electricity taxes

applied to all producers. Hence this type of instrument

differs from premium feed-in tariffs only in

terms of the cash flow for RES-E producers; it

represents a negative cost instead of additional

revenue.

Overview of the Different RES-E

Support Schemes in EU-27 Countries

Figure III.4.1 shows the evolution of the different

RES-E support instruments from 1997 to 2007 in each

of the EU-27 Member States. Some countries already

have more than ten years’ experience with RES-E support

schemes.

Initially, in the old EU-15, only 8 out of the 15

Member States avoided a major policy shift between

1997 and 2005. The current discussion within EU

Member States focuses on the comparison between

two opposing systems – the FIT system and quota

regulation in combination with a TGC market. The

latter has recently replaced existing policy instruments

in some European countries, such as Belgium,

Italy, Sweden, the UK and Poland. Although these

new systems were not introduced until after 2002,

the announced policy changes caused investment

instabilities prior to this date. Other policy instruments,

such as tender schemes, are no longer used

as the main policy scheme in any European country.

However, there are instruments, such as production

tax incentives and investment incentives, that are

frequently used as supplementary instruments; only

Finland and Malta use them as their main support

scheme.

Table III.4.2 gives a detailed overview of the main

support schemes for wind energy in the EU-27 Member

States.

In Table III.4.3, a more detailed overview is provided

on implemented RES-E support schemes in the EU-27

Member States in 2007, detailing countries, strategies

and the technologies addressed. In the EU-27,

FITs serve as the main policy instrument.

For a detailed overview of the EU Member States’

support schemes, please refer to Appendix I.

Evaluation of the Different RES-E

Support Schemes (Effectiveness

and Economic Efficiency)

In reviewing and evaluating the different RES-E

support schemes described above, the key question

is whether each of these policy instruments has been

a success. In order to assess the success of the


230 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.4.1: Evolution of the main policy support schemes in EU-27 Member States

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

AT

BE

All RES-E technologies

All RES-E technologies

BG All RES-E technologies

CY All RES-E technologies

Feed-in tariff

Quota/TGC

Tender

Tax incentives/

investment grants

Change of

the system

Adaptation of

the system

CZ

All RES-E technologies

DK All RES-E technologies

EE

All RES-E technologies

FI

All RES-E technologies

FR

Wind

Bioenergy

PV

DE All RES-E technologies

HU All RES-E technologies

GR All RES-E technologies

IE

IT

LT

All RES-E technologies

Wind

Bioenergy

PV

All RES-E technologies

LU

All RES-E technologies

LV

All RES-E technologies

MT

Wind

Bioenergy

PV

NL

All RES-E technologies

PL

All RES-E technologies

PT

All RES-E technologies

ES

All RES-E technologies

RO All RES-E technologies

SE

All RES-E technologies

SI

All RES-E technologies

SK All RES-E technologies

UK All RES-E technologies

Source: Ragwitz et al. (2007)


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 231

Table III.4.2: Overview of the main RES-E support schemes for wind energy in the EU-27 Member States

as implemented in 2007

Country

Main support

instrument for wind

Settings of the main support instrument for wind in detail

Austria FIT New fixed feed-in tariff valid for new RES-E plants permitted in 2006 and/or 2007: fixed FIT for

years 1–9 (€76.5/MWh for 2006 as a starting year; €75.5/MWh for 2007). Years 10 and 11 at

75% and year 12 at 50%.

Belgium

Bulgaria

Quota obligation

system with TGC,

combined with

minimum price

for wind

Mandatory purchase

price

Flanders, Wallonia and Brussels have introduced a quota obligation system (based on TGCs).

The minimum price for wind onshore (set by the federal government) is €80/MWh in Flanders,

€65/MWh in Wallonia and €50/MWh in Brussels. Wind offshore is supported at the federal level,

with a minimum price of €90/MWh (the first 216 MW installed at €107/MWh minimum).

Mandatory purchase prices (set by the State Energy Regulation Commission): new wind

installations after 1 January 2006 (duration 12 years each): (i) effective operation >2250 h/a:

€79.8/MWh; (ii) effective operation


232 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.4.2: (continued)

Country

Latvia

Main support

instrument for wind

Main policy support

instrument currently

under development

Settings of the main support instrument for wind in detail

Frequent policy changes and short duration of guaranteed feed-in tariffs (phased out in 2003)

result in high investment uncertainty. Main policy currently under development.

Lithuania FIT Fixed feed-in tariff (since 2002): €63.7/MWh, guaranteed for 10 years.

Luxembourg FIT Fixed feed-in tariff: (i) 0.5 MW: max €77.6/MWh (i.e. decreasing

for higher capacities); guaranteed for 10 years.

Malta

Netherlands

Poland

No support instrument

yet

Premium Tariff

(€0/MWh since

August 2006)

Quota obligation

system; TGCs

introduced end 2005

plus renewables

are exempted from

excise tax

Very little attention to RES-E (including wind) support so far. A low VAT rate is in place.

Premium feed-in tariffs guaranteed for 10 years were in place from July 2003. For each MWh

RES-E generated, producers receive a green certificate. The certificate is then delivered to

the feed-in tariff administrator to redeem tariff. Government put all premium RES-E support

at zero for new installations from August 2006 as it believed target could be met with

existing applicants.

Obligation on electricity suppliers with RES-E targets specified from 2005 to 2010. Poland has

a RES-E and primary energy target of 7.5% by 2010. RES-E share in 2005 was 2.6% of gross

electricity consumption.

Portugal FIT Fixed feed-in tariff (average value 2006): €74/MWh, guaranteed for 15 years.

Romania

Quota obligation

system with TGCs

Obligation on electricity suppliers with targets specified from 2005 (0.7% RES-E) to 2010

(8.3% RES-E). Minimum and maximum certificate prices are defined annually by Romanian

Energy Regulatory Authority. Non-compliant suppliers pay maximum price (i.e. €63/MWh

for 2005–2007; €84/MWh for 2008–2012).

Slovakia FIT Fixed feed-in tariff (since 2005): €55–72/MWh; FITs for wind are set that way so that a rate of

return on the investment is 12 years when drawing a commercial loan.

Slovenia

Spain

Sweden

UK

Choice between FIT

and premium tariff

Choice between FIT

and premium tariff

Quota obligation

system with TGCs

Quota obligation

system with TGCs

Fixed feed-in tariff: (i) 1 MW: €59/MWh.

Premium tariff: (i) 1 MW: €25/MWh.

Fixed feed-in tariff and premium tariff guaranteed for 5 years, then reduced by 5%. After ten

years reduced by 10% (compared to original level).

Fixed feed-in tariff: (i) 5 MW: €68.9/MWh;

Premium tariff: (i) 5 MW: €38.3/MWh.

Duration: no limit, but fixed tariffs are reduced after either 15, 20 or 25 years,

depending on technology.

Obligation (based on TGCs) on electricity consumers. Obligation level of 51% RES-E defined to

2010. Non-compliance leads to a penalty, which is fixed at 150% of the average certificate price

in a year (average certificate price was €69/MWh in 2007).

Obligation (based on TGCs) on electricity suppliers. Obligation target increases to 2015 (15.4%

RES-E; 5.5% in 2005) and guaranteed to stay at least at that level until 2027. Electricity

companies which do not comply with the obligation have to pay a buy-out penalty (€65.3/MWh

in 2005). Tax exemption for electricity generated from RES is available.

Sources: Auer (2008); Ragwitz et al. (2007)


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 233

Table III.4.3: Overview of the main RES-E support schemes in the EU-27 Member States as implemented in 2007

Country

Austria

Main electricity

support schemes

FITs combined with

regional investment

incentives

Comments

Until December 2004, FITs were guaranteed for 13 years. In November 2005 it was announced

that, from 2006 onwards, full FITs would be available for 10 years, with 75% available in year

11 and 50% in year 12. New FIT levels are announced annually and support is granted on a

first-come, first-served basis. From May 2006 there has been a smaller government budget for

RES-E support. At present, a new amendment is tabled, which suggests extending the duration

of FIT fuel-independent technologies to 13 years (now 10 years) and fuel-dependent technologies

to 15 years (now 10 years).

Belgium

Bulgaria

Quota obligation system/

TGC combined with

minimum prices for

electricity from RES

Mandatory purchase

of renewable electricity

by electricity suppliers

for minimum prices

(essentially FITs) plus

tax incentives

The federal government has set minimum prices for electricity from RES.

Flanders and Wallonia have introduced a quota obligation system (based on TGCs) with the

obligation on electricity suppliers. In all three of the regions, including Brussels, a separate market

for green certificates has been created. Offshore wind is supported at the federal level.

The relatively low level of incentives makes the penetration of renewables particularly difficult,

since the current commodity prices for electricity are still relatively low. A green certificate

system to support renewable electricity developments has been proposed, for implementation

in 2012, to replace the mandatory purchase price. Bulgaria recently agreed upon an indicative

target for renewable electricity with the European Commission, which is expected to provide a

good incentive for further promotion of renewable support schemes.

Cyprus FITs (since 2006), An Enhanced Grant Scheme was introduced in January 2006, in the form of government grants

supported by investment worth 30–55% of investment, to provide financial incentives for all renewable energy. FITs with

grant scheme for the long-term contracts (15 years) were also introduced in 2006.

promotion of RES

Czech

Republic

Denmark

FITs (since 2002), Relatively high FITs, with a lifetime guarantee of support. Producers can choose fixed FITs or a

supported by investment premium tariff (green bonus). For biomass co-generation, only green bonus applies. FIT levels are

grants

announced annually, but are increased by at least 2% each year.

Premium FIT for onshore

wind, tender scheme for

offshore wind and fixed

FITs for others

Duration of support varies from 10 to 20 years, depending on the technology and scheme applied.

The tariff level is generally rather low compared to the formerly high FITs. A net metering approach

is taken for photovoltaics.

Estonia FIT system FITs paid for 7–12 years, but not beyond 2015. Single FIT level for all RES-E technologies.

Relatively low FITs make new renewable investments very difficult.

Finland

France

Energy tax exemption

combined with

investment incentives

FITs plus tenders for

large projects

Tax refund and investment incentives of up to 40% for wind and up to 30% for electricity

generation from other RES.

For power plants 12 MW (except wind) a tendering scheme is in place.

Germany FITs FITs are guaranteed for 20 years (Renewable Energy Act) and soft loans are also available.

Greece

FITs combined with

investment incentives

FITs are guaranteed for 12 years, with the possibility of extension up to 20 years. Investment

incentives up to 40%.

Hungary

FIT (since January

2003, amended 2005),

combined with purchase

obligation and grants

Fixed FITs recently increased and differentiated by RES-E technology. There is no time limit for

support defined by law, so in theory guaranteed for the lifetime of the installation. Plans to

develop TGC system; when this comes into effect, the FIT system will cease to exist.

Ireland

FIT scheme replaced

tendering scheme

in 2006

New premium FITs for biomass, hydropower and wind started in 2006. Tariffs guaranteed to

supplier for up to 15 years. Purchase price of electricity from the generator is negotiated between

generators and suppliers. However, support may not extend beyond 2024, so guaranteed premium

FIT payments should start no later than 2009.

continued


234 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.4.3: (continued)

Country

Main electricity

support schemes

Comments

Italy

Latvia

Quota obligation system

with TGCs; fixed FIT

for PV

Main policy under

development; quota

obligation system (since

2002) without TGCs,

combined with FITs

(phased out in 2003)

Obligation (based on TGCs) on electricity producers and importers. Certificates are issued

for RES-E capacity during the first 12 years of operation, except for biomass, which receives

certificates for 100% of electricity production for the first 8 years and 60% for the next 4 years.

Separate fixed FIT for PV, differentiated by size, and building integrated. Guaranteed for 20 years.

Increases annually in line with retail price index.

Frequent policy changes and short duration of guaranteed FITs result in high investment

uncertainty. Main policy currently under development.

Quota system (without TGCs) typically defines small RES-E amounts to be installed. High

FIT scheme for wind and small hydropower plants (less than 2 MW) was phased out as from

January 2003.

Lithuania

FITs combined with

purchase obligation

Relatively high fixed FITs for hydro (


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 235

Table III.4.3: (continued)

Country

Slovenia

Main electricity

support schemes

FITs, CO 2 taxation and

public funds for

environmental

investments

Comments

Renewable electricity producers choose between fixed FITs and premium FITs. Tariff levels defined

annually by Slovenian Government (but have not changed since 2004).

Tariff guaranteed for 5 years, then reduced by 5%. After 10 years, reduced by 10% (compared to

original level). Relatively stable tariffs combined with long-term guaranteed contracts makes

system quite attractive to investors.

Spain FITs Electricity producers can choose a fixed FIT or a premium on top of the conventional electricity

price. No time limit, but fixed tariffs are reduced after either 15, 20 or 25 years depending on

technology. System very transparent. Soft loans, tax incentives and regional investment incentives

are available.

Sweden

UK

Quota obligation system

with TGCs

Quota obligation system

with TGCs

Obligation (based on TGCs) on electricity consumers. Obligation level defined to 2010. Noncompliance

leads to a penalty, which is fixed at 150% of the average certificate price in a year.

Investment incentive and a small environmental bonus available for wind energy.

Obligation (based on TGCs) on electricity suppliers. Obligation target increases to 2015 and

guaranteed to stay at that level (as a minimum) until 2027. Electricity companies that do not

comply with the obligation have to pay a buy-out penalty. Buy-out fund is recycled back to

suppliers in proportion to the number of TGCs they hold. The UK is currently considering

differentiating certificates by RES-E technology.

Tax exemption for electricity generated from RES is available (Levy Exemption Certificates,

which give exemption from the Climate Change Levy).

Source: Ragwitz et al. (2007)

different policy instruments, the most important

criteria are:

• Effectiveness: Did the RES-E support programmes

lead to a significant increase in deployment of

capacities from RES-E in relation to the additional

potential? The effectiveness indicator measures

the relationship of the new generated electricity

within a certain time period to the potential of the

technologies.

• Economic efficiency: What was the absolute support

level compared to the actual generation costs of

RES-E generators, and what was the trend in support

over time? How is the net support level of RES-E

generation consistent with the corresponding effectiveness

indicator?

Other important performance criteria are the credibility

for investors and the reduction of costs over

time. However, effectiveness and economic efficiency

are the two most important criteria – these are discussed

in detail in the following sections.

EFFECTIVENESS OF POLICY INSTRUMENTS

When analysing the effectiveness of RES-E support

instruments, the quantities installed are of particular

interest. In order to be able to compare the performance

between the different countries, the figures are

related to the size of the population. Here we look at all

new RES-E in total, as well as wind and PV in detail.

Figure III.4.2 depicts the effectiveness of total

RES-E policy support for the period 1998 to 2005,

measured in yearly additional electricity generation in

comparison to the remaining additional available

potential for each EU-27 Member State. The calculations

refer to following principle:

E i G i n - G i n-1

n = _________

ADDPOT i = G i n - G i ______________ n-1

n POT i

2020 - G i n-1


236 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.4.2: Policy effectiveness of total RES-E support for 1998–2005 measured in annual additional electricity generation

in comparison to the remaining additional available potential for each EU-27 Member State

10%

Effectiveness indicator – total RES-E (%)

8%

6%

4%

2%

0%

–2%

–4%

AT BE BG CY CZ DE DK EE ES FI FR GR HU IE IT LT LULV MT NL PL PT RO SE SI SK UK EU-

27

–6%

Feed-in tariff

Tender

Trend in 2005

Quota/TGC

Tax incentives/investment grants

Average effectiveness indicator

Source: Eurostat (2007a)

Effectiveness indicator for RES

technology i for the year n

E i n

Additional generation potential

of RES technology i in year n

until 2020

ADDPOT i n

Existing electricity generation

potential by RES technology i

in year n

G i n

Total generation potential of

RES technology i until 2020

POT i n

It is clearly indicated in Figure III.4.2 that countries

with FITs as a support scheme achieved higher effectiveness

compared to countries with a quota/TGC system

or other incentives. Denmark achieved the highest

effectiveness of all the Member States, but it is

important to remember that very few new generation

plants have been installed in recent years. Conversely,

in Germany and Portugal there has been a significant

increase in new installations recently. Among the new

Member States, Hungary and Poland have implemented

the most efficient strategies in order to promote ‘new’

renewable energy sources.

ECONOMIC EFFICIENCY

Next we compare the economic efficiency of the support

programmes described above. In this context,

three aspects are of interest:

1. absolute support levels;

2. total costs to society; and

3. dynamics of the technology.

Here, as an indicator, the support levels are compared

specifically for wind power in the EU-27 Member

States.

Figure III.4.3 shows that the support level and

generation costs are almost equal. Countries with

relatively high average generation costs frequently

show a higher support level, but a clear deviation from

this rule can be found in the three quota systems in

Belgium, Italy and the UK, for which the support is

presently significantly higher than the generation costs.


WIND ENERGY - THE FACTS - PRICES AND SUPPORT MECHANISMS 237

Figure III.4.3: Onshore wind: support level ranges (average to maximum support) in EU countries in 2006 (average tariffs are

indicative) compared to the long-term marginal generation costs (minimum to average costs)

200

180

160

140

120

100

80

60

40

20

0

AT BG CY DE EE FI GR HU IS LA LU NL PL RO SI TR

Minimum to average generation costs ( /MWh)

Average to maximum support level ( /MWh)

Note: Support level is normalised to 15 years.

Source: Adapted from Ragwitz et al. (2007)

The reasons for the higher support level, expressed by

the current green certificate prices, may differ; but the

main reasons are risk premiums, immature TGC markets

and inadequate validity times of certificates (Italy

and Belgium).

For Finland, the level of support for onshore wind is

too low to initiate any steady growth in capacity. In

the case of Spain and Germany, the support level indicated

in Figure III.4.3 appears to be above the average

level of generation costs. However, the potential with

fairly low average generation costs has already been

exploited in these countries, due to recent market

growth. Therefore, a level of support that is moderately

higher than average costs seems to be reasonable.

In an assessment over time, the potential

technology learning effects should also be taken into

account in the support scheme.

Figure III.4.4 illustrates a comparative overview of

the ranges of TGC prices and FITs in selected EU-27

countries. With the exception of Sweden, TGC prices

are much higher than those for guaranteed FITs, which

also explains the high level of support in these countries,

as shown in Figure III.4.4.

Policy Recommendations for the

Design Criteria of RES-E Support

Instruments

CONSIDERATION OF A DYNAMIC PORTFOLIO

OF RES-E SUPPORT SCHEMES

Regardless of whether a national or international support

system is concerned, a single instrument is not

usually enough to stimulate the long-term growth of

RES-E. Since, in general, a broad portfolio of RES technologies

should be supported, the mix of instruments

selected should be adjusted accordingly. Whereas

investment grants are normally suitable for supporting

immature technologies, FITs are appropriate for

the interim stage of the market introduction of a


238 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.4.4: Comparison of premium support level: FIT premium support versus value of TGCs

120

120

FIT premium support ( /MWh)

100

80

60

40

20

Value of TGCs ( /MWh)

100

80

60

40

20

0

202

0

302 2004 2005

302

402 2005

Austria

Germany

Netherlands

Spain – fixed tariff

Spain – premium

France

Greece

Portugal

Czech Republic

Slovenia

Italy

Wallonia

UK – RO

Sweden

Flanders

Note: The FIT premium support level consists of FIT minus the national average spot market electricity price.

Source: EEG (2007)

technology. A premium, or a quota obligation based on

TGC, is likely to be the most relevant choice when:

• markets and technologies are sufficiently mature;

• the market size is large enough to guarantee competition

among the market actors; and

• competition on the conventional power market is

guaranteed.

Such a mix of instruments can then be supplemented

by tender procedures, which are very efficient, for

example, in the case of large-scale projects such as

offshore wind.

STRIVING FOR OPTIMAL RES-E INSTRUMENT

DESIGN IN TERMS OF EFFECTIVENESS AND

EFFICIENCY

Most instruments still have significant potential for

improvement, even after the minimum design criteria

described above have been met. A few examples of

such optimisation options are as follows:

• In a feed-in system, a stepped design can clearly

increase the economic efficiency of the instrument,

especially in countries where the productivity of a

technology varies significantly between different

technology bands.

• In quota systems based on TGCs, the technology or

band specification that is currently being tested in

Italy (based on technology-specific certification periods)

and in Belgium (based on technology-specific

certificate values) may be a relevant option for

increasing both the instrument’s effectiveness and

its efficiency. However, such technology specification

should not be carried out by setting technologyspecific

quotas and separating the TGC market, as

this would negatively influence market liquidity.

Furthermore, the risk premium might go down if minimum

tariffs were to be introduced in a quota system.


III.5

WIND POWER ON THE SPOT MARKET

Introduction

In a number of countries, wind power has an increasing

share of total power production. This applies particularly

to countries such as Denmark, Spain and

Germany, where the shares of wind in terms of total

power supply are currently 21 per cent, 12 per cent

and 7 per cent respectively. In these cases, wind

power is becoming an important player in the power

market, and such high shares can significantly influence

prices.

Different power market designs have a significant

influence on the integration of wind power. In the following

section, short descriptions of the most important

market designs within the increasingly liberalised

European power industry are presented, along with

more detailed descriptions of spot and balancing markets.

Finally, the impacts of Danish wind power on the

Scandinavian power exchange, NordPool’s Elspot,

which comprises Denmark, Norway, Sweden and

Finland, are discussed in more detail.

Power Markets

As part of the gradual liberalisation of the EU electricity

industry, power markets are increasingly organised

in a similar way, where a number of closely related

services are provided. This applies to a number of liberalised

power markets, including those of the Nordic

countries, Germany, France and The Netherlands.

Common to all these markets is the existence of five

types of power market:

• Bilateral electricity trade or OTC (over the counter)

trading: Trading takes place bilaterally outside the

power exchange, and prices and amounts are not

made public.

• The day-ahead market (spot market): A physical

market where prices and amounts are based on

supply and demand. Resulting prices and the

overall amounts traded are made public. The spot

market is a day-ahead market where bidding closes

at noon for deliveries from midnight and 24 hours

ahead.

• The intraday market: Quite a long time period

remains between close of bidding on the day-ahead

market and the regulating power market (below).

The intraday market is therefore introduced as an

‘in-between market’, where participants in the dayahead

market can trade bilaterally. Usually, the

product traded is the one-hour-long power contract.

Prices are published and based on supply and

demand.

• The regulating power market (RPM): A real-time

market covering operation within the hour. The

main function of the RPM is to provide power regulation

to counteract imbalances related to dayahead

operations planned. Transmission system

operators (TSOs) alone make up the demand side

of this market, and approved participants on the

supply side include both electricity producers

and consumers.

• The balancing market: This market is linked to the

RPM and handles participant imbalances recorded

during the previous 24-hour period of operation. The

TSO alone acts on the supply side to settle imbalances.

Participants with imbalances on the spot

market are price takers on the RPM/balance

market.

The day-ahead and regulating markets are particularly

important for the development and integration of

wind power in the power systems. The Nordic power

exchange, NordPool, is described in more detail in

the following section as an example of these power

markets.

THE NORDIC POWER MARKET:

NordPool SPOT MARKET

The NordPool spot market (Elspot) is a day-ahead market,

where the price of power is determined by supply

and demand. Power producers and consumers submit


240 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

their bids to the market 12 to 36 hours in advance of

delivery, stating the quantities of electricity supplied

or demanded and the corresponding price. Then, for

each hour, the price that clears the market (balancing

supply with demand) is determined on the NordPool

power exchange.

In principle, all power producers and consumers

can trade on the exchange, but in reality, only big consumers

(distribution and trading companies and large

industries) and generators act on the market, while

the smaller companies form trading cooperatives (as

is the case for wind turbines), or engage with larger

traders to act on their behalf. Approximately 45 per

cent of total electricity production in the Nordic countries

is traded on the spot market. The remaining share

is sold through long-term, bilateral contracts, but the

spot price has a considerable impact on prices agreed

in such contracts. In Denmark, the share sold at the

spot market is as high as 80 per cent.

Figure III.5.1 shows a typical example of an annual

supply and demand curve for the Nordic power system.

As shown, the bids from nuclear and wind power enter

Figure III.5.1: Supply and demand curve for the NordPool

power exchange

the supply curve at the lowest level, due to their low

marginal costs, followed by combined heat and power

plants, while condensing plants are those with the

highest marginal costs of power production. Note that

hydropower is not identified on the figure, since bids

from hydro tend to be strategic and depend on precipitation

and the level of water in reservoirs.

In general, the demand for power is highly inelastic

(meaning that demand remains almost unchanged in

spite of a change in the power price), with mainly

Norwegian and Swedish electro-boilers and powerintensive

industry contributing to the very limited

price elasticity.

If power can flow freely in the Nordic area – that is

to say, transmission lines are not congested – then

there will only be one market price. But if the required

power trade cannot be handled physically, due to transmission

constraints, the market is split into a number

of sub-markets, defined by the pricing areas. For example,

Denmark splits into two pricing areas (Jutland/

Funen and Zealand). Thus, if more power is produced

in the Jutland/Funen area than consumption and

transmission capacity can cover, this area would

constitute a sub-market, where supply and demand

would balance out at a lower price than in the rest of

the NordPool area.

€/MWh

THE NORDIC POWER MARKET:

THE REGULATING MARKET

Supply

Price

Wind and nuclear

Source: Risø DTU

Demand

CHP plants

MWh

Gas turbines

Condensing

plants

Imbalances in the physical trade on the spot market

must be levelled out in order to maintain the balance

between production and consumption, and to maintain

power grid stability. Totalling the deviations from bid volumes

on the spot market yields a net imbalance for that

hour in the system as a whole. If the grid is congested,

the market breaks up into area markets, and equilibrium

must be established in each area. The main tool for correcting

such imbalances, which provides the necessary

physical trade and accounting in the liberalised Nordic

electricity system, is the regulating market.


WIND ENERGY - THE FACTS - WIND POWER ON THE SPOT MARKET 241

The regulating power market and the balancing

market may be regarded as one entity, where the

TSO acts as an important intermediary or facilitator

between the supply and demand of regulating power.

The TSO is the body responsible for securing the

system functioning in a region. Within its region, the

TSO controls and manages the grid, and to this end,

the combined regulating power and balancing market

is an important tool for managing the balance and stability

of the grid (Nordel, 2002). The basic principle

for settling imbalances is that participants causing or

contributing to the imbalance will pay their share of

the costs for re-establishing balance. Since September

2002, the settling of imbalances among Nordic countries

has been done based on common rules. However,

the settling of imbalances within a region differs from

country to country. Work is being done in Nordel to

analyse the options for harmonising these rules in the

Nordic countries.

If the vendors’ offers or buyers’ bids on the spot market

are not fulfilled, the regulating market comes into

force. This is especially important for wind electricity

producers. Producers on the regulating market have to

deliver their offers one or two hours before the hour of

delivery, and power production must be available

within 15 minutes of notice being given. For these reasons,

only fast-response power producers will normally

be able to deliver regulating power.

It is normally only possible to predict the supply of

wind power with a certain degree of accuracy 12–36

hours in advance. Consequently, it may be necessary

to pay a premium for the difference between the volume

offered to the spot market and the volume delivered.

Figure III.5.2 shows how the regulatory market functions

in two situations: a general deficit on the market

(left part of the figure) and a general surplus on the

market (right part of figure).

If the market tends towards a deficit of power, and

if power production from wind power plants is lower

than offered, other producers will have to adjust regulation

(up) in order to maintain the power balance.

In this case, the wind producer will be penalised and

get a lower price for their electricity production than

the spot market price. The further off-track the wind

producer is, the higher the expected penalty. The difference

between the regulatory curves and the stipulated

spot market price in Figure III.5.2 illustrates

this. If wind power production is higher than the

amount offered, wind power plants effectively help

to eliminate market deficit and therefore receive

the spot price for the full production without paying

a penalty.

If the market tends towards an excess of power, and

if power production from the wind power plant is higher

than offered, other producers will have to adjust regulation

(down) in order to maintain the power balance.

Figure III.5.2: The functioning of the regulatory market

Market in deficit of power

Market in excess of power

Expected level

Plant in deficit

production

Plant in surplus

production

Expected level

Plant in deficit

production

Plant in surplus

production

Penalty

Penalty

Price

Price

Source: Risø DTU


242 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

In this case, the wind producer will be penalised and

get a lower price for their electricity production than

the spot market price. Again, the further off-track the

wind producer, the higher the expected premium.

However, if wind power production is lower than

the bid, then wind power plants help to eliminate surplus

on the market, and therefore receive the spot

price for the full amount of production without paying

a penalty.

Until the end of 2002, each country participating in

the NordPool market had its own regulatory market. In

Denmark, balancing was handled by agreements with

the largest power producers, supplemented by the

possibility of TSOs buying balancing power from abroad

if domestic producers were too expensive or unable to

produce the required volumes of regulatory power. A

common Nordic regulatory market was established at

the beginning of 2003, and both Danish areas participate

in this market.

In Norway, Sweden and Finland, all suppliers on the

regulating market receive the marginal price for power

regulation at the specific hour. In Denmark, market

suppliers get the price of their bid to the regulation

market. If there is no transmission congestion, the

regulation price is the same in all areas. If bottlenecks

occur in one or more areas, bids from these areas on

the regulating market are not taken into account when

forming the regulation price for the rest of the system,

and the regulation price within the area will differ from

the system regulation price.

In Norway, only one regulation price is defined, and

this is used both for sale and purchase, at the hour

when settling the imbalances of individual participants.

This implies that participants helping to

eliminate imbalances are rewarded even if they do not

fulfil their actual bid. Thus if the market is in deficit of

power and a wind turbine produces more than its bid,

then the surplus production is paid a regulation

premium corresponding to the penalty for those plants

in deficit.

The Impact of Wind Power on the

Power Market – Illustrated by the

Case of Denmark

Denmark has a total capacity of a little more than

3200 MW of wind power – approximately 2800 MW

from land turbines and 400MW offshore. In 2007,

around 21 per cent of domestic power consumption

was supplied by wind power, which makes Denmark

the leading country in terms of wind power penetration

(followed by Spain, where the share of wind as a total

of electricity consumption is 12 per cent).

Figure III.5.3 shows wind power’s average monthly

coverage of power consumption in Denmark. Normally,

the highest wind-generated production is from January

to March. However, as 2006 was a bad wind year in

Denmark, this was not the case. The contribution during

the summer is normally at a fairly low level.

Considerable hourly variations are found in wind

power production for Western Denmark, as illustrated

in Figure III.5.4. January 2007 was a tremendously

Figure III.5.3: The share of wind power in power consumption

calculated as monthly averages for 2006

Wind power/power consumption

35

30

25

20

15

10

5

0

Source: Risø DTU

Jan Feb Mar Apr May Jun

Jul Aug Sep Oct Nov Dec


WIND ENERGY - THE FACTS - WIND POWER ON THE SPOT MARKET 243

Figure III.5.4: Wind power as a percentage of domestic power consumption in January 2007 (hourly basis)

140

120

Wind production/power consumption (%)

100

80

60

40

20

0

1 49 97 145 193 241 289 337 385 433 481 529 577 625 673 721

Hours in January 2007

Source: Risø DTU

good wind month, with an average supply of 44 per

cent of power consumption in Western Denmark, and,

as shown, wind-generated power exceeded power

consumption on several occasions. Nevertheless,

there were also periods with low or no wind in January.

In such cases, wind power can significantly influence

price determination on the power market. This will be

discussed in more detail in the following section.

HOW DOES WIND POWER INFLUENCE THE

POWER PRICE AT THE SPOT MARKET?

Wind power is expected to influence prices on the

power market in two ways:

1. Wind power normally has a low marginal cost (zero

fuel costs) and therefore enters near the bottom of

the supply curve. This shifts the supply curve to

the right (see Figure III.5.5), resulting in a lower

power price, depending on the price elasticity of

the power demand. In general, the price of power is

expected to be lower during periods of high wind

than in periods of low wind.

2. As mentioned above, there may be congestions

in power transmission, especially during periods

with high wind power generation. Thus, if the available

transmission capacity cannot cope with the

required power export, the supply area is separated

from the rest of the power market and constitutes

its own pricing area. With an excess supply of

power in this area, conventional power plants have

to reduce their production, since it is generally not

possible to limit the power production of wind. In

most cases, this will lead to a lower power price in

this sub-market.


244 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.5.5: How wind power influences the power spot

price at different times of the day

€/MWh

Price

Source: Risø DTU

Wind and nuclear

Demand Supply

Day Peak

Night

Gas turbines

CHP

plants

Condensing

plants

MWh

The way in which wind power influences the power

spot price, due to its low marginal cost, is shown in

Figure III.5.5. When wind power supply increases, it

shifts the power supply curve to the right. At a given

demand, this implies a lower spot price on the power

market, as shown. However, the impact of wind power

depends on the time of day. If there is plenty of wind

power at midday, during peak power demand, most of

the available generation will be used. This implies that

we are at the steep part of the supply curve (see

Figure III.5.5) and, consequently, wind power will have

a strong impact, reducing the spot power price significantly.

But if there is plenty of wind-produced electricity

during the night, when power demand is low and

most power is produced on base load plants, we are at

the flat part of the supply curve and consequently the

impact of wind power on the spot price is low.

The congestion problem arises because Denmark,

especially the Western Region, has a very high share

of wind power, and in cases of high wind power production,

transmission lines are often fully utilised.

In Figure III.5.6, this congestion problem is illustrated

for January 2007, when the share of wind-generated

electricity in relation to total power consumption for

West Denmark was more than 100 per cent at certain

periods (Figure III.5.6 left part). This means that during

these periods, wind power supplied more than all the

power consumed in that area. If the prioritised production

from small, decentralised CHP plants is added on

top of wind power production, there are several periods

with a significant excess supply of power, part of which

may be exported. However, when transmission lines are

fully utilised, there is a congestion problem. In that

case, equilibrium between demand and supply needs to

be reached within the specific power area, requiring

conventional producers to reduce their production, if

possible. The consequences for the spot power price

are shown in the right graph of Figure III.5.6. By

comparing the two graphs, it can be clearly seen that

there is a close relationship between wind power in the

system and changes in the spot price for this area.

The consequences of the two issues mentioned

above for the West Denmark power supply area are

discussed below. It should be mentioned that similar

studies are available for Germany and Spain, which

show almost identical results.

IMPACTS OF WIND POWER ON

SPOT PRICES

The analysis here entails the impacts of wind power on

power spot prices being quantified using structural

analyses. A reference is fixed, corresponding to a situation

with zero contribution from wind power in the

power system. A number of levels with increasing contributions

from wind power are then identified and,

relating to the reference, the effect of wind power’s

power production is calculated. This is illustrated in

the left-hand graph in Figure III.5.7, where the shaded

area between the two curves approximates the value

of wind power in terms of lower spot power prices.

In the right-hand graph in Figure III.5.7, more detail is

shown with figures from the West Denmark area. Five

levels of wind power production and the corresponding


WIND ENERGY - THE FACTS - WIND POWER ON THE SPOT MARKET 245

Figure III.5.6: Left – wind power as percentage of power consumption in Western Denmark; Right – spot prices for the same

area and time period

120%

600

Wind production/power consumption (%)

100

80

60

40

20

DKK/MWh

500

400

300

200

100

0

1

Source: Risø DTU

49 97 145 193 241 289 337

385 433 481 529 577 625

Hours in January 2007

673 0

1 67 265 331

727

127

133 199 397 463 529 595 661

Denmark West price

Hours in January 2007

System price

power prices are depicted for each hour of the day

during December 2005. The reference is given by the

‘0–150 MW’ curve, which thus approximates those

hours of the month when the wind was not blowing.

Therefore, this graph should approximate the prices for

an average day in December 2005, in a situation with

zero contribution from wind power. The other curves

show increasing levels of wind power production: the

150–500 MW curve shows a situation with low wind,

increasing to storm in the >1500 MW curve. As shown,

the higher the wind power production, the lower the spot

power price is in this area. At very high levels of wind

power production, the power price is reduced significantly

during the day, but only falls slightly during the

night. Thus there is a significant impact on the power

price, which might increase in the long term if even

larger shares of wind power are fed into the system.

Figure III.5.7 relates to December 2005, but similar

figures are found for most other periods during 2004

and 2005, especially in autumn and winter, owing to

the high wind power production in these periods.

Of course, ‘noise’ in the estimations does exist,

implying ‘overlap’ between curves for the single categories

of wind power. Thus, a high amount of wind

power does not always imply a lower spot price than

that with low wind power production, indicating that a

significant statistical uncertainty exists. Of course,

factors other than wind power production influence

prices on the spot market. But the close correlation

between wind power and spot prices is clearly verified

by a regression analysis carried out using the West

Denmark data for 2005, where a significant relationship

is found between power prices, wind power production

and power consumption.


246 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.5.7: The impact of wind power on the spot power price in the West Denmark power system in December 2005

DKK/MWh

800

700

600

500

400

300

Lower spot price because

of wind power production

No wind

Nice wind

DKK/MWh

800

700

600

500

400

300

December power price

0–150 MW

150–500 MW

500–1000 MW

1000–1500 MW

>1500 MW

200

200

100

100

0

0

1 4 7 10 13 16 19 22 1 4 7 10 13 16 19 22

Hour of the day

Hour of the day

Note: The calculation only shows how the production contribution from wind power influences power prices when the wind is blowing. The analysis cannot be used to answer

the question ‘What would the power price have been if wind power was not part of the energy system?’.

Source: Risø DTU

When wind power reduces the spot power price, it

has a significant influence on the price of power for

consumers. When the spot price is lowered, this is

beneficial to all power consumers, since the reduction

in price applies to all electricity traded – not only to

electricity generated by wind power.

Figure III.5.8 shows the amount saved by power consumers

in Western and Eastern Denmark due to wind

Figure III.5.8: Annual percentage and absolute savings by power consumers in Western and Eastern Denmark in 2004–2007

due to wind power depressing the spot market electricity price

16

Denmark West

0.6

Power consumers saved

14

12

Denmark East

Total

0.5

% lower spot price

10

8

6

c€/kWh

0.4

0.3

0.2

4

2

0.1

0

0

2004 2005 2006 2007 2004 2005 2006 2007

Source: Risø DTU


WIND ENERGY - THE FACTS - WIND POWER ON THE SPOT MARKET 247

power’s contribution to the system. Two calculations

were performed: one using the lowest level of wind

power generation as the reference (‘0–150 MW’), in

other words assuming that the power price would have

followed this level if there was no contribution from

wind power in the system, and the other more conservative,

utilising a reference of above 500 MW. For each

hour, the difference between this reference level and

the levels with higher production of wind power is calculated.

Summing the calculated amounts for all hours

of the year gives the total benefit for power consumers

of wind power lowering spot prices of electricity.

Figure III.5.8 shows how much higher the consumer

price would have been (excluding transmission tariffs,

taxes and VAT) if wind power had not contributed to

power production.

In general in 2004–2007, the cost of power to the

consumer (excluding transmission and distribution tariffs,

taxes, and VAT) would have been approximately

4–12 per cent higher in Denmark if wind power had not

contributed to power production. Wind power’s strongest

impact is estimated to have been for Western

Denmark, due to the high penetration of wind power

in this area. In 2007, this adds up to approximately

0.5c€/kWh saved by power consumers as a result of

wind power lowering electricity prices, compared to the

support given to wind power as FITs of approximately

0.7c€/kWh. Thus, although the expenses of wind power

are still greater than the financial benefits for power

consumers, a significant reduction of net expenses is

certainly achieved due to lower spot prices.

Finally, though having a smaller impact, wind power

clearly reduces power prices even within the large

Nordic power system. Thus although wind power in the

Nordic countries is mainly established in Denmark, all

Nordic power consumers benefit financially due to the

presence of Danish wind power on the market.


III.6

WIND POWER COMPARED TO CONVENTIONAL

POWER GENERATION

In this chapter, the cost of conventionally generated

power is compared with the cost of wind-generated

power. To obtain a comparable picture, calculations for

conventional technologies are prepared utilising the

Recabs model, which was developed in the IEA Implementing

Agreement on Renewable Energy Technology

Deployment (IEA, 2008). The cost of conventional

electricity production in general is determined by four

components:

1. fuel cost;

2. cost of CO 2 emissions (as given by the European

Trading System for CO 2 , ETS);

3. operation and maintenance (O&M) costs; and

4. capital cost, including planning and site work.

Fuel prices are given by the international markets

and, in the reference case, are assumed to develop

according to the IEA’s World Energy Outlook 2007

(IEA, 2007c), which rather conservatively assumes a

crude oil price of US$63/barrel in 2007, gradually

declining to $59/barrel in 2010 (constant terms). Oil

prices reached a high of $147/barrel in July 2008. As

is normally observed, natural gas prices are assumed

to follow the crude oil price (basic assumptions

on other fuel prices: coal €1.6/GJ and natural gas

€6.05/GJ). As mentioned, the price of CO 2 is determined

by the EU ETS market; at present the price of

CO 2 is around €25/t.

Here, calculations are carried out for two state-ofthe-art

conventional plants: a coal-fired power plant

and a combined cycle natural gas combined heat and

power plant, based on the following assumptions:

• Plants are commercially available for commissioning

by 2010.

• Costs are levelised using a 7.5 per cent real discount

rate and a 40-year lifetime (national assumptions

on plant lifetime might be shorter, but calculations

were adjusted to 40 years).

• The load factor is 75 per cent.

• Calculations are carried out in constant 2006-€.

When conventional power is replaced by windgenerated

electricity, the costs avoided depend on the

degree to which wind power substitutes for each of

the four components. It is generally accepted that

implementing wind power avoids the full fuel and CO 2

costs, as well as a considerable portion of the O&M

costs of the displaced conventional power plant. The

level of avoided capital costs depends on the extent to

which wind power capacity can displace investments

in new conventional power plants, and thus is directly

tied to how wind power plants are integrated into the

power system.

Studies of the Nordic power market, NordPool, show

that the cost of integrating variable wind power is, on

average, approximately 0.3–0.4c€/kWh of wind power

generated at the present level of wind power capacity

(mainly Denmark) and with the existing transmission

and market conditions. These costs are completely in

line with experiences in other countries. Integration

costs are expected to increase with higher levels of

wind power penetration.

Figure III.6.1 shows the results of the reference

case, assuming the two conventional power plants

are coming on-stream in 2010. As mentioned, figures

for the conventional plants are calculated using the

Recabs model, while the costs for wind power are

taken from Chapter III.1.

As shown in the reference case, the cost of power

generated at conventional power plants is lower than the

cost of wind-generated power under the given assumptions

of lower fuel prices. Wind-generated power at a

European inland site is approximately 33–34 per cent

more expensive than natural gas- and coal-generated

power.

This case is based on the World Energy Outlook

assumptions on fuel prices, including a crude oil price

of $59/barrel in 2010. At present (September 2008),

the crude oil price is $120/barrel. Although this oil

price is combined with a lower exchange rate for US

dollar, the present price of oil is significantly higher


WIND ENERGY - THE FACTS - WIND POWER COMPARED TO CONVENTIONAL POWER GENERATION 249

Figure III.6.1: Costs of generated power comparing conventional plants to wind power, 2010 (constant 2006-€)

80

70

60

Regulation costs

CO 2 – 25/t

Basic

/MWh

50

40

30

20

10

0

Coal

Natural gas

Wind power –

coastal site

Wind power –

inland site

Source: Risø DTU

Figure III.6.2: Sensitivity analysis of costs of generated power comparing conventional plants to wind power, assuming

increasing fossil fuel and CO 2 prices, 2010 (constant 2006-€)

100

80

Regulation costs

CO 2 – €35/t

Basic

/MWh

60

40

20

0

Coal Coal + 50% Natural gas Natural gas

x 2

Wind power –

coastal site

Wind power –

inland site

Source: Risø DTU


250 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

than the forecast IEA oil price for 2010. Therefore, a

sensitivity analysis is carried through and results are

shown in Figure III.6.2.

In Figure III.6.2, the natural gas price is assumed to

double compared to the reference, equivalent to an oil

price of $118/barrel in 2010, the coal price to

increase by 50 per cent and the price of CO 2 to

increase to €35/t from €25/t in 2008. As shown in

Figure III.6.2, the competitiveness of wind-generated

power increases significantly: costs at the inland site

become lower than generation costs for the natural

gas plant and only around 10 per cent more expensive

than the coal-fired plant. At coastal sites, wind power

produces the cheapest electricity.

Finally, as discussed by Awerbuch (2003a), the

uncertainties related to future fossil fuel prices

mentioned above imply a considerable risk for future

generation costs of conventional plants. Conversely,

the costs per kWh generated by wind power are almost

constant over the lifetime of the turbine, following

its installation. Thus, although wind power might currently

be more expensive per kWh, it can account for

a significant share in a utilities’ portfolio of power

plants, since it hedges against unexpected rises in

prices of fossil fuels in the future. The consistent

nature of wind power costs justifies a relatively higher

cost compared to the uncertain risky future costs of

conventional power.


III.7

EMPLOYMENT

Employment in the Wind

Energy Sector

WIND ENERGY EMPLOYMENT IN EUROPE

Wind energy companies in the EU currently employ

around 108,600 people. 6 For the purposes of this

chapter, direct jobs relate to employment in wind turbine

manufacturing companies and with sub-contractors

whose main activity is supplying wind turbine

components. Also included are wind energy promoters,

utilities selling electricity from wind energy, and major

R&D, engineering and specialised wind energy services.

Any companies producing components, providing

services, or sporadically working in wind-related

activities are deemed to provide indirect employment.

The addition of indirect employment affects results

significantly. The European Commission, in its EC Impact

Assessment on the Renewable Energy Roadmap (EC,

2006), found that 150,000 jobs were linked to wind

energy. The European Renewable Energy Council

(EREC, 2007) report foresees a workforce of 184,000

people in 2010, but the installed capacity for that year

has probably been underestimated. Therefore, the

figure for total direct and indirect jobs is estimated

at approximately 154,000 jobs.

These two figures of 108,600 direct and 154,000

total jobs can be compared with the results obtained

by EWEA in its previous survey for Wind Energy – The

Facts (EWEA, 2003) of 46,000 and 72,275 workers

respectively. The growth experienced between 2003 and

2007 (236 per cent) is consistent with the evolution

of the installed capacity in Europe (276 per cent –

EWEA, 2008b) during the same period and with the

fact that most of the largest wind energy companies

are European.

A significant proportion of the direct wind energy

employment (around 75 per cent) is in three countries,

Denmark, Germany and Spain, whose combined installed

capacity adds up to 70 per cent of the total in the EU.

Nevertheless, the sector is less concentrated now than

it was in 2003, when these three countries accounted

for 89 per cent of the employment and 84 per cent of the

EU installed capacity. This is due to the opening of manufacturing

and operation centres in emerging markets and

to the local nature of many wind-related activities, such

as promotion, O&M, engineering and legal services.

Germany (BMU, 2006 and 2008) is the country

where most wind-related jobs have been created, with

around 38,000 directly attributable to wind energy

companies 7 and a slightly higher amount from indirect

effects. According to the German Federal Ministry of

the Environment, in 2007 over 80 per cent of the value

chain in the German wind energy sector was exported.

Table III.7.1: Direct employment from wind energy

companies in selected European countries

Country

No of direct jobs

Austria 700

Belgium 2000

Bulgaria 100

Czech Republic 100

Denmark 23,500

Finland 800

France 7000

Germany 38,000

Greece 1800

Hungary 100

Ireland 1500

Italy 2500

The Netherlands 2000

Poland 800

Portugal 800

Spain 20,500

Sweden 2000

UK 4000

Rest of EU 400

TOTAL 108,600

Sources: Own estimates, based on EWEA (2008a); ADEME (2008); AEE (2007);

DWIA (2008); BMU (2008)


252 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

In Spain (AEE, 2007), direct employment is 20,500

people. When indirect jobs are taken into account, the

figure goes up to 37,730. According to the AEE,

30 per cent of the jobs are in manufacturing companies;

34 per cent in installation, O&M and repair companies,

27 per cent in promotion and engineering

companies, and 9 per cent in other branches.

Denmark (DWIA, 2008) has around 23,500 employees

in wind turbine and blade manufacturing and major

sub-component corporations. 8

The launch of new wind energy markets has fostered

the creation of employment in other EU countries.

Factors such as market size, proximity to one of the

three traditional leaders, national regulation and labour

costs determine the industry structure, but the effect

is always positive.

France (2454 MW installed, 888 MW added in 2007

and an estimated figure of 7000 wind energy jobs),

for instance, shows a wealth of small developers, consultants,

and engineering and legal service companies.

All the large wind energy manufacturers and

developers and some utilities have opened up a branch

in this country. France also counts on several wind

turbine and component manufacturers producing in

its territory.

In the UK, the importance of offshore wind energy

and small-scale wind turbines is reflected by the existence

of many job-creating businesses in this area.

This country also has some of the most prestigious

wind energy engineering and consultancy companies.

The British Wind Energy Association is conducting a

study of present and future wind energy employment;

preliminary results point to the existence of around

4000 to 4500 direct jobs.

Another example is Portugal, where the growth of the

market initially relied on imported wind turbines. From

2009 onwards, two new factories will be opened, adding

around 2000 new jobs to the 800 that already exist.

Some other EU Member States, such as Italy,

Greece, Belgium, The Netherlands, Ireland and Sweden,

are also in the 1500 to 2500 band. The situation in the

new Member States is diverse, with Poland in a leading

position. Wind energy employment will probably

rise significantly in the next three to five years, boosted

by a combination of market attractiveness, a highly

skilled labour force and lower production costs.

In terms of gender, the survey conducted by EWEA

shows that males make up 78 per cent of the workforce.

In the EU labour market as a whole, the figure is

55.7 per cent. Such a bias reflects the traditional predominance

of men in production chains, construction

work and engineering.

By type of company, wind turbine and component

manufacturers account for most of the jobs (59 per

cent). Within these categories, companies tend to be

bigger and thus employ more people.

Wind energy figures can be measured against the

statistics provided by Eurostat (2007). The energy sector

employs 2.69 million people, accounting for 1.4 per

cent of total EU employment. Approximately half this

Figure III.7.1: Direct employment by type of company,

according to EWEA survey

Financial/

insurance

R&D/university

0.3%

1%

Others

Consultancy/

1%

engineering

3%

Installation/

repair/O&M

11%

IPP/utility

9%

Developers

16%

Source: EWEA (2008a)

Component

manufacturers

22%

Manufacturers

37%


WIND ENERGY - THE FACTS - EMPLOYMENT 253

amount is active in the production of electricity, gas,

steam and hot water. Employment from the wind energy

sector would then make up around 7.3 per cent of that

amount; and it should be noted that wind energy currently

meets 3.7 per cent of EU electricity demand.

Although the lack of specific data for electricity production

prevents us from making more accurate comparisons,

this shows that wind energy is more labour intensive

than the other electricity generating technologies. This

conclusion is consistent with earlier research.

Finally, there is a well-documented trend of energy

employment decline in Europe, particularly marked in

the coal sector. For instance, British coal production

and employment have dropped significantly, from

229,000 workers in 1981 to 5500 in 2006. In

Germany, it is estimated that jobs in the sector will

drop from 265,000 in 1991 to less than 80,000 in

2020. In EU countries, more than 150,000 utility and

gas industry jobs disappeared in the second half of the

1990s and it is estimated that another 200,000 jobs

will be lost during the first half of the 21st century

(UNEP, ILO and ITUC, 2007). The outcomes set out in

the previous paragraphs demonstrate that job losses

in the European energy sector are independent of

renewable energy deployment and that the renewable

energy sector is, in fact, helping to mitigate these

negative effects in the power sector.

JOB PROFILES OF THE WIND

ENERGY INDUSTRY

The lack of any official classification of wind energy

companies makes it difficult to categorise wind energy

jobs. However, Table III.7.2 summarises the main

profiles required by wind energy industries, according

to the nature of their core business.

THE SHORTAGE OF WORKERS

In the last two to three years, wind energy companies

have repeatedly reported a serious shortage of workers,

especially within certain fields. This scarcity coincides

with a general expansion of the European economy,

where growth rates have been among the fastest since

the end of the Second World War. An analysis of

Eurostat (2008b) statistics proves that job vacancies

have been difficult to cover in all sectors. The rotation

of workers is high, both for skilled and non-skilled

workers.

In the case of wind energy, the general pressure

provoked by strong economic growth is complemented

by the extraordinary performance of the sector since

the end of the 1990s. In the 2000–2007 period, wind

energy installations in the EU increased by 339 per

cent (EWEA, 2008b). This has prompted an increase

in job offers in all the sub-sectors, especially in manufacturing,

maintenance and development activities.

Generally speaking, the shortage is more acute for

positions that require a high degree of experience and

responsibility:

• From a manufacturer’s point of view, two major

bottlenecks arise: one relates to engineers dealing

with R&D, product design and the manufacturing

processes; the other to O&M and site management

activities (technical staff).

• In turn, wind energy promoters lack project managers;

the professionals responsible for getting the

permits in the country where a wind farm is going

to be installed. These positions require a combination

of specific knowledge of the country and wind

energy expertise, which is difficult to gain in a

short period of time.

• Other profiles, such as financiers or sales managers,

can sometimes be hard to find, but generally this is

less of a problem for wind energy companies, possibly

because the necessary qualifications are more

general.

• The picture for the R&D institutes is not clear: of

the two consulted, one reported no problems, while

the other complained that it was impossible to hire

experienced researchers. It is worth noting that the

remuneration offered by R&D centres, especially if


254 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Table III.7.2: Typical wind energy job profiles demanded by different types of industry

Company type Field of activity Main job profiles

Wind energy

manufacturers

Wind turbine

producers, including

manufacturers of

major sub-components

and assembly

factories.

• Highly qualified chemical, electrical, mechanical and materials engineers dealing with

R&D issues, product design, management and quality control of production process.

• Semi-skilled and non-skilled workers for the production chains.

• Health and safety experts.

• Technical staff for the O&M and repair of wind turbines.

• Other supporting staff (including administrative, sales managers, marketing and

accounting).

Developers

Construction, repair

and O&M

Independent power

producers, utilities

Manage all the

tasks related to the

development of wind

farms (planning,

permits, construction

and so on).

Construction of the

wind farm, regular

inspection and repair

activities. 9

Operation of the wind

farm and sale of the

electricity produced.

• Project managers (engineers and economists) to coordinate the process.

• Environmental engineers and other specialists to analyse the environmental impacts of

wind farms.

• Programmers and meteorologists for wind energy forecasts and prediction models.

• Lawyers and economists to deal with the legal and financial aspects of project development.

• Other supporting staff (including administrative, sales managers, marketing and

accounting).

• Technical staff for the O&M and repair of wind turbines.

• Electrical and civil engineers for the coordination of construction works.

• Health and safety experts.

• Specialists in the transport of heavy goods.

• Electricians.

• Technical staff specialised in wind turbine installation, including activities in cranes,

fitters and nacelles.

• Semi-skilled and non-skilled workers for the construction process.

• Other supporting staff (including administrative, sales managers and accounting).

• Electrical, environmental and civil engineers for the management of plants.

• Technical staff for the O&M of plants, if this task is not sub-contracted.

• Health and safety experts.

• Financiers, sales and marketing staff to deal with the sale of electricity.

• Other supporting staff (including administrative and accounting).

Consultancies, Diverse specialised

legal entities, activities linked to the

engineering, wind energy business.

financial institutions,

insurers, R&D

centres and others

• Programmers and meteorologists for the analysis of wind regimes and output forecasts.

• Engineers specialised in aerodynamics, computational fluid dynamics and other R&D areas.

• Environmental engineers.

• Energy policy experts.

• Experts in social surveys, training and communication.

• Financiers and economists.

• Lawyers specialised in energy and environmental matters.

• Marketing personnel and event organisers.

they are governmental or university-related, is below

the levels offered by private companies.

The quality of the university system does not seem

to be at the root of the problem, although recently

graduated students often need an additional specialisation

that is given by the wind company itself. The

general view is that the number of engineers graduating

from European universities on an annual basis

does not meet the needs of modern economies,

which rely heavily on manufacturing and technological

sectors.

In contrast, there seems to be a gap in the secondary

level of education, where the range and quality of courses

dealing with wind-related activities (mainly O&M, health

and safety, logistics, and site management) are inadequate.

Policies aimed at improving the educational

programmes at pre-university level – dissemination

campaigns, measures to encourage worker mobility

and vocational training for the unemployed – can help


WIND ENERGY - THE FACTS - EMPLOYMENT 255

overcome the bottleneck, and at the same time ease

the transition of staff moving from declining sectors.

Employment Prediction

and Methodology

METHODOLOGICAL APPROACHES TO

EMPLOYMENT QUANTIFICATION

The quantification of wind energy employment is a

difficult task for several reasons. First, it encompasses

many company profiles, such as equipment

manufacturing, electricity generation, consulting

services, finance and insurance, which belong to

different economic sectors. Second, we cannot rely

on any existing statistics to estimate wind energy

figures, as they do not distinguish between electricity

and equipment manufacturing branches. And

finally, the structure of the sector changes rapidly and

historical data cannot be easily updated to reflect

the current situation.

For these reasons, measurement initiatives must

rely on a number of methodologies, which can largely

be grouped under two headings:

1. data collection based on surveys and complemented

by other written evidence; and

2. data collection based on estimated relationships

between sectors, vectors of activity and input/

output tables.

Surveys

Surveys are the best way to collect information on

direct employment, especially when additional aspects –

gender issues, employment profiles, length of contracts

and other qualitative information – need to be incorporated.

Surveys have significant limitations, notably

the correct identification of the units that need to be

studied and the low percentage of responses (see, for

example, Rubio and Varas, 1999; Schuman and Stanley,

1996; Weisberg et al., 1996). When these problems

arise, results need to be extrapolated and completed

by other means.

Estimated Relationships

Estimated relationships, including input/output

tables, can be used to estimate both direct and indirect

employment impacts. These models require some

initial information, collected by means of a questionnaire

and/or expert interviews, but then work on the

basis of technical coefficients (Leontief, 1986; Kulisic

et al., 2007). The advantages of estimated models

are based on the fact that they reflect net economic

changes in the sector that is being studied, other

related economic sectors and the whole of the economic

system. These models also constitute the basis

for the formulation of forecasts. The disadvantages

relate to the cost of carrying out such studies and the

need to obtain an appropriate model. In addition, they

do not provide any details at sub-sector level and do

not capture gender-related, qualification and shortage

issues.

In the last six or seven years, coinciding with the

boom of the wind energy sector, several studies have

been conducted on the related employment repercussions.

A list of the most relevant works can be found in

Appendix J. A careful revision of their methodology

shows that many of them are, in reality, meta-analyses

(that is to say, a critical re-examination and comparison

of earlier works), while research based on questionnaires

and/or input/output tables is less common.

Denmark, Germany and Spain, being the three world

leaders in wind energy production and installation, have

produced solid studies (AEE, 2007; DWIA, 2008; Lehr

et al., 2008; BMU, 2008), but employment in the other

EU markets remains largely unknown. In particular,

there is a lack of information on some key features affecting

the wind energy labour market, such as the profiles

that are currently in demand, shortages and gender

issues. These issues can best be dealt with through

ad hoc questionnaires sent to wind energy companies.


256 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

EWEA SURVEY ON DIRECT EMPLOYMENT

As a response to the gaps mentioned above, EWEA

has sought to quantify the number of people directly

employed by the wind energy sector in Europe by means

of a questionnaire. As explained in the previous section

on wind energy employment in Europe (page 251),

direct jobs relate to employment within wind turbine

manufacturing companies and sub-contractors whose

main activity is the supply of wind turbine components.

Also taken into account are wind energy promoters,

utilities selling electricity from wind energy, and major

R&D, engineering and specialised wind energy services.

Any other company producing components, providing

services, or sporadically working in wind-related activities

is deemed as providing indirect employment.

The analysts have attempted to minimise the main

disadvantages linked to this type of methodology.

Consequently, the questionnaire was drafted after

careful analysis of previous research in this field, notably

the questionnaires that had been used in the German,

Danish and Spanish studies, and following a discussion

with the researchers responsible for these. A draft was

sent to a reduced number of respondents, who then

commented on any difficulties in understanding the

questions and using the Excel spreadsheet, the length

of the questionnaire, and some other aspects. The

document was modified accordingly.

The final version of the questionnaire was dispatched

by email on 19 February 2008 to around 1100 organisations

in 30 countries (the 27 EU Member States plus

Croatia, Norway and Turkey). It reached all EWEA

members and the members of the EU-27 national wind

energy associations. The questionnaire was also distributed

among participants of the last two European

Wind Energy Conferences (EWEC 2006 and 2007).

These included:

• wind turbine and component manufacturers;

• developers;

• independent power producers and utilities;

• installation, repair and O&M companies;

• consultancies;

• engineering and legal services;

• R&D centres;

• laboratories and universities;

• financial institutions and insurers;

• wind energy agencies and associations; and

• other interest groups directly involved in wind energy

matters.

The document was translated into five EU languages

(English, French, German, Spanish and Portuguese),

and a number of national wind energy associations

decided to write the introductory letter in their own

language. A reminder was sent out on 11 March,

followed up by telephone calls during April, May, June,

July and August.

The questionnaire consisted of 11 questions, divided

into three blocks:

1. The first four questions collected information on

the profile of the company, its field of activity and

the year in which it started operating in the wind

energy sector.

2. The next three questions aimed to obtain relevant

employment figures. The questionnaire requested

both the total number of employees and the number

of employees in the wind energy sector, and gave

some indication about how to calculate the second

figure when a worker was not devoted to windrelated

activities full time. The figures were divided

up by country, since some companies are transnational,

and by sex. It would have been interesting

to classify this data by age and level of qualification,

but the draft sent to a sample of respondents

showed us that this level of detail would be very

difficult to obtain and that it would have had a

negative impact on the number of replies.

3. The final four questions addressed the issue of labour

force scarcity in the wind energy sector, and aimed

to obtain information on the profiles that are in short

supply and the prospects of wind energy companies

in terms of future employment levels and profiles.


WIND ENERGY - THE FACTS - EMPLOYMENT 257

Questions 9 and 10 were more speculative, since it

is difficult to quantify the exact employment

demands in the next five years, but they gave an

order of magnitude that could then be compared

with the quantitative approaches of input/output

tables used by other researchers.

The questionnaire was complemented by in-depth

interviews with a selection of stakeholders that suitably

reflected the main wind energy sub-sectors and

EU countries. The interviews were carried out by

phone, by email or face-to-face. They were aimed at

verifying the data obtained from the questionnaires

and at addressing some of the topics that could not

be dealt with, notably a more thorough explanation of

the job profiles demanded by the industry and the

scarcity problem.

By the end of August 2008, 324 valid questionnaires

had been received, implying a response rate of around

30 per cent. When looking at the responses, it is clear

that it was mostly the largest turbine and component

manufacturers, as well as the major utilities, that

answered the questionnaire. The replies therefore do

not provide an accurate representation of the industry

as a whole.

The figures are good for this type of survey, but supplementary

sources need to be used to fill in the gaps

and validate results. This has been done in several

ways:

• The use of thematic surveys and input/output analysis

carried out in Denmark, France, Germany and

Spain. The last two countries base their numbers

on questionnaires very similar to the ones used by

EWEA, an exhaustive analysis of the governmental

registers for tax-related purposes, and the application

of national input/output tables and other technical

coefficients to estimate the indirect effects.

The Danish Wind Energy Association collects

information about employment from all its members

on an annual basis and then predicts indirect and

induced jobs through technical coefficients and

Table III.7.3: EWEA survey results 10

Country

No of direct jobs

Austria 270

Belgium 1161

Bulgaria 91

Cyprus 1

Czech Republic 52

Denmark 9875

Estonia 5

Finland 194

France 2076

Germany 17,246

Greece 812

Hungary 11

Ireland 870

Italy 1048

Latvia 6

Lithuania 6

The Netherlands 824

Poland 312

Portugal 425

Romania 27

Slovakia 22

Slovenia 4

Spain 10,986

Sweden 1234

UK 2753

Rest of Europe 70

TOTAL 50,380

Source: EWEA (2008a)

multipliers. The French Environment and Energy

Management Agency (ADEME) bases its estimates

on net production/employment ratios (imports have

been disregarded).

• The review of the annual reports/websites of the

main wind energy companies, notably the large wind

energy manufacturers, component manufacturers,

wind energy developers and utilities. As these


258 WIND ENERGY - THE FACTS - THE ECONOMICS OF WIND POWER

Figure III.7.2: Number of questionnaires received by type

of company

Installation/

repair/O&M

49

R&D/university

18

Consultancy/

engineering

91

IPP/utility

73

Source: EWEA (2008a)

Financial/

insurance

11

Energy agency/

assoc./lobby

10

Other

34

Developers

132

Activity in several

categories

105

Wind turbine

manufacturers

19

Component

manufacturers

35

companies are active in the stock market, they

publish some information on their activities and

structure that can be used to estimate wind energy

figures.

• The registers and the expertise gained by the

national wind energy associations. France, the UK

and Portugal are currently carrying out thematic

studies covering, among other things, employment

issues. Their preliminary conclusions have been

incorporated into this publication. In other cases,

experts from the national associations and governments

have been contacted.

Additionally, EWEA is engaged in an in-depth examination

of the factors that are behind the repeatedly

reported shortage of workers in the wind energy sector

and the profiles that are particularly difficult to

find. This has been done through in-depth interviews

(conducted face-to-face, by email and by phone) with

the human resources managers of a selection of wind

energy companies from different branches and geographical

areas. The results were compared with those

of the answers to questions 7–10 of the general

questionnaire.

Part III Notes

1

‘Ex-works’ means that site work, foundation and grid

connection costs are not included. Ex-works costs include

the turbine as provided by the manufacturer, which includes

the turbine, blades, tower and transport to the site.

2

In Spain land rental is counted as an O&M cost.

3

The number of observations was generally between 25

and 60.

4

See, for instance, Neij (1997), Neij et al. (2003) or

Milborrow (2003).

5

This is in line with observed costs in other countries.

6

For more information on wind energy employment, see

EWEA (2008c).

7

The 2006 BMU study found that 43 per cent of gross

wind energy jobs (63,900) were direct; the rest, which

also included O&M, were indirect. In 2008, the BMU

published new data (84,300 jobs), but this does not

distinguish between direct and indirect jobs. For the

purposes of this publication, we have made the split

based on the assumption that the earlier ratio still

pertains (43 per cent direct and 57 per cent indirect).

8

Of those, 13,000 come from pure wind turbine and blade

manufacturing companies. The remaining 4000 are

attributed to major sub-suppliers. Most of these produce

for more than one sector. In this publication, such

companies are included within the category of ‘direct

employment’ when at least 50 per cent of their turnover

comes from sales to wind turbine manufacturers or

operators. In addition, the questionnaire that was used as

the basis for obtaining the statistics asked about ‘jobs

that can be attributed to wind-related activities’, thus

eliminating staff that are devoted to other activities.

9

The Windskill Project (www.windskill.eu/) funded by the

European Commission offers a good summary of the

profiles that are required in this area.

10

In a few cases, the questionnaires were filled in by the

researchers themselves. This occurred when the figures

were communicated through a phone call or by email, or

when the information needed was available in an annual

report or some other publicly available company

document.

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